Filed pursuant to Rule 424(b)(4)

Registration No. 333-128332

PROSPECTUS

Regency Energy Partners LP

13,750,000 Common Units

Representing Limited Partner Interests

     This is the initial public offering of our common units. We are a limited partnership recently formed by Hicks, Muse, Tate & Furst Incorporated, our sponsor. We have been approved to list our common units on the Nasdaq National Market under the symbol “RGNC.”

     Investing in our common units involves risks. Please read “Risk factors.”

     These risks include the following:

•  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner.

•  The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted.

•  If we do not receive the revenues we anticipate from the expansion and enhancement of our intrastate pipeline, our cash flow and our ability to make cash distributions to you may be adversely affected.

•  Because of the natural decline in production from existing wells, our success depends on our ability to obtain new supplies of natural gas, which involves factors beyond our control. Any decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

•  Natural gas, natural gas liquids and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions to you.

•  Our sponsor will own a 62.7% limited partner interest in us and will control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to your detriment.

•  Our reimbursement of our general partner’s fees and expenses will reduce our cash available for distribution to you.

•  Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

•  Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

•  Control of our general partner may be transferred to a third party without unitholder consent.

•  You will experience immediate and substantial dilution of $18.11 per common unit.

•  You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

     We will use approximately 76.6% of the net proceeds from this offering to make a distribution to the HMTF Investors, who own our general partner, and an additional 18.7% of the net proceeds to replenish working capital that will be distributed to the HMTF Investors immediately prior to the consummation of this offering. Please see “Use of Proceeds.”

	Per Common Unit		Total
Initial public offering price	$	20.0000	$	275,000,000
Underwriting discount(1)	$	1.2125	$	16,671,875
Proceeds to Regency Energy Partners LP (before expenses)	$	18.7875	$	258,328,125

(1)  Excludes structuring fee of $1,375,000.

     We have granted the underwriters a 30-day option to purchase up to an additional 2,062,500 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 13,750,000 common units in this offering. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem an equal number of common units held by the HMTF Investors.

     Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

     The underwriters expect to deliver the common units against payment in New York, New York on or about February 3, 2006.

UBS Investment Bank Lehman Brothers

Citigroup Wachovia Securities

A.G. Edwards KeyBanc Capital Markets

January 30, 2006

TABLE OF CONTENTS

		Page
SUMMARY			1
	Regency Energy Partners LP		1
	Gathering and Processing Segment		1
	Transportation Segment		2
	Business Strategies		2
	Competitive Strengths		3
	Summary of Risk Factors		3
	Formation Transactions and Partnership Structure		5
	Management of Regency Energy Partners		7
	Principal Executive Offices and Internet Address		7
	The Offering		8
	Summary Historical and Pro Forma Financial and Operating Data		11
	Non-GAAP Financial Measures		13
RISK FACTORS			15
	Risks Related to Our Business		15
	Risks Inherent in an Investment in Us		26
	Tax Risks to Common Unitholders		30
USE OF PROCEEDS			33
CAPITALIZATION			34
DILUTION			35
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			36
	General		36
	Cash Distributions		37
	Our Initial Distribution Rate		37
	Pro Forma Financial Information and Financial Forecast		38
FORECASTED CASH AVAILABLE FOR DISTRIBUTION FOR THE TWELVE MONTHS ENDING DECEMBER 31, 2006			50
	Pro Forma Available Cash for Year Ended December 31, 2004 and Twelve Months Ended September 30, 2005		52
HOW WE MAKE CASH DISTRIBUTIONS			57
	Operating Surplus and Capital Surplus		57
	Subordination Period		58
	Distributions of Available Cash from Operating Surplus During the Subordination Period		59
	Distributions of Available Cash from Operating Surplus After the Subordination Period		60
	Incentive Distribution Rights		60
	Percentage Allocations of Available Cash from Operating Surplus		60
	Distributions from Capital Surplus		61
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		62
	Distributions of Cash Upon Liquidation		62
SELECTED HISTORICAL AND SELECTED PRO FORMA FINANCIAL AND OPERATING DATA			65
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			67
	Overview		67
	Our Operations		67
	How We Evaluate Our Operations		70
	General Trends and Outlook		71
	Formation, Acquisition and Asset Disposal History and Financial Statement Presentation		72
	Items Impacting Comparability of Our Financial Results		76
	Critical Accounting Policies and Estimates		77
	Results of Operations		79
	Other Matters		85
	Liquidity and Capital Resources		86
	Capital Requirements		90
	Recent Accounting Pronouncements		93
	Quantitative and Qualitative Disclosures About Market Risk		93

		Page
BUSINESS			96
	Overview		96
	Business Strategies		97
	Competitive Strengths		99
	Industry Overview		100
	Gathering and Processing Operations		101
	Transportation Operations		109
	Other Assets		112
	Our Contracts		112
	Competition		113
	Risk Management		113
	Regulation		114
	Environmental Matters		116
	Title to Properties		120
	Office Facilities		121
	Employees		121
	Legal Proceedings		121
MANAGEMENT			122
	Management of Regency Energy Partners LP		122
	Directors and Executive Officers		123
	Reimbursement of Expenses of Our General Partner		126
	Executive Compensation		127
	Employment and Severance Agreements		128
	Compensation of Directors		128
	Long-Term Incentive Plan		129
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			131
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			133
	Distributions and Payments to Our General Partner and its Affiliates		133
	Agreements Governing the Transactions		134
	Omnibus Agreement		134
	Related Party Transactions Prior to the HMTF Investors’ Acquisition of Regency Gas Services LLC		135
	Limited Partner Interests to be Received by Certain Members of Management		135
	Limited Partner Interests to be Received by Certain Directors		136
	General Partner Interests		137
	Related Party Transactions with the HMTF Investors		137
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			138
	Conflicts of Interest		138
	Fiduciary Duties		141
DESCRIPTION OF THE COMMON UNITS			144
	The Units		144
	Transfer Agent and Registrar		144
	Transfer of Common Units		144
THE PARTNERSHIP AGREEMENT			145
	Organization and Duration		145
	Purpose		145
	Power of Attorney		145
	Capital Contributions		145
	Voting Rights		145
	Limited Liability		147
	Issuance of Additional Securities		148
	Amendment of the Partnership Agreement		148
	Merger, Sale or Other Disposition of Assets		150
	Termination and Dissolution		150
	Liquidation and Distribution of Proceeds		151
	Withdrawal or Removal of the General Partner		151
	Transfer of General Partner Interest		152
	Transfer of Ownership Interests in the General Partner		153
	Transfer of Incentive Distribution Rights		153

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		Page
	Change of Management Provisions		153
	Limited Call Right		153
	Meetings; Voting		154
	Status as Limited Partner		154
	Non-Citizen Assignees; Redemption		155
	Indemnification		155
	Reimbursement of Expenses		155
	Books and Reports		155
	Right to Inspect Our Books and Records		156
	Registration Rights		156
UNITS ELIGIBLE FOR FUTURE SALE			157
MATERIAL TAX CONSEQUENCES			158
	Partnership Status		158
	Limited Partner Status		159
	Tax Consequences of Unit Ownership		160
	Tax Treatment of Operations		164
	Disposition of Common Units		165
	Uniformity of Units		167
	Tax-Exempt Organizations and Other Investors		168
	Administrative Matters		168
	State, Local and Other Tax Considerations		170
INVESTMENT IN REGENCY ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS			172
UNDERWRITING			173
	Option to Purchase Additional Common Units		173
	Commissions and Discounts		173
	No Sales of Similar Securities		174
	Indemnification		174
	Directed Unit Program		175
	Nasdaq National Market Quotation		175
	Price Stabilization, Short Positions		175
	Determination of Offering Price		176
	Electronic Distribution		176
	Discretionary Sales		176
	Stamp Taxes		176
	Affiliations		177
VALIDITY OF THE COMMON UNITS			178
EXPERTS			178
WHERE YOU CAN FIND MORE INFORMATION			178
FORWARD-LOOKING STATEMENTS			178
INDEX TO FINANCIAL STATEMENTS			F-1
Appendix A — First Amended & Restated Agreement of Limited Partnership of Regency Energy Partners LP			A-1
Appendix B — Glossary of Terms			B-1

      You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

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      Until February 24, 2006 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

      References in this prospectus to “Regency Energy Partners,” “we,” “our,” “us” or like terms, when used in a historical context, refer to both Regency Gas Services LLC, all of the outstanding member interests of which are being contributed to Regency Energy Partners LP in connection with this offering, and the subsidiaries of Regency Gas Services LLC. When used in the present tense or prospectively, those terms refer to Regency Energy Partners LP and its subsidiaries. References to “Hicks Muse” refer to Hicks, Muse, Tate & Furst Incorporated. References to the “HMTF Investors” refer to Regency Acquisition LLC, HMTF Regency, LP, Hicks Muse and funds managed by Hicks Muse, including the Hicks, Muse, Tate & Furst Equity Fund V, L.P., and certain co-investors, including some of our directors and management. Regency Acquisition LLC is wholly owned by HMTF Regency, LP. HMTF Regency, LP is wholly owned by Hicks Muse, funds managed by Hicks Muse and certain co-investors.

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SUMMARY

      This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters’ option to purchase additional units is not exercised. We were recently formed as a Delaware limited partnership. Please see “— Formation Transactions and Partnership Structure” for more information about our formation. You should read “Risk Factors” for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

Regency Energy Partners LP

      We are a Delaware limited partnership recently formed by Hicks Muse to capitalize on opportunities in the midstream sector of the natural gas industry. This is the initial public offering of our common units. We intend to pay holders of our common units distributions of available cash of $0.35 per unit for each quarter, or $1.40 per unit annually, before we pay any distributions to the holders of our subordinated units.

      We are a growth-oriented independent midstream energy partnership engaged in the gathering, processing, marketing and transportation of natural gas and natural gas liquids, or NGLs. We provide these services through systems located in north Louisiana, west Texas and the mid-continent region of the United States, primarily in Kansas and Oklahoma.

      We divide our operations into two business segments:

•  Gathering and Processing: provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate the NGLs and delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

•  Transportation: delivers natural gas from northwest Louisiana to north central Louisiana through our 280-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our pipeline enhancement project.

Gathering and Processing Segment

      We operate our Gathering and Processing segment in three geographic areas of the United States: north Louisiana, west Texas and the mid-continent region, which includes Kansas, Oklahoma, Colorado, and the Texas panhandle. Our gathering and processing assets include five cryogenic processing plants, of which four are currently active, and approximately 2,950 miles of related gathering and pipeline infrastructure connected to approximately 2,650 active wells. In north Louisiana, we own a large gathering system that is connected to two processing plants that we own and operate. In west Texas, we own a large gathering system that is connected to a processing plant that we own and operate. In the mid-continent region, we own three large gathering systems, one of which is connected to a processing plant that we own and operate. Our Gathering and Processing segment also includes our NGL marketing business through which we sell the NGLs that are produced by our processing plants for our own account and for the accounts of our customers.

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      The following table contains information regarding our gathering systems and processing plants as of September 30, 2005:

									Throughput
			Length		Wells		Compression		Capacity
Region	Asset Type		(Miles)		Connected		(Horsepower)		(MMcf/d)
North Louisiana		Gathering pipelines		600		700		14,500		300
		Processing facilities		—		—		10,000		90
West Texas		Gathering pipelines		750		450		22,000		200
		Processing facility		—		—		20,000		125
Mid-Continent		Gathering pipelines		1,600		1,500		41,500		265
		Processing facility		—		—		3,650		50	(1)

(1)  Excludes 80 MMcf/d of throughput capacity available at our inactive Lakin processing facility.

Transportation Segment

      Our Transportation segment consists of our Regency Intrastate Pipeline system, a 280-mile natural gas pipeline in north Louisiana that transports natural gas primarily from northwest Louisiana to north central Louisiana where it connects to a number of interstate and intrastate pipelines. As of September 30, 2005, the Regency Intrastate Pipeline system had a capacity of 250 MMcf/d with 17,900 horsepower of compression and a 35 MMcf/d refrigeration plant for hydrocarbon dewpoint control. During the nine months ended September 30, 2005, the system had average throughput of 232 MMcf/d.

      Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result, we have completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. This project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.

      The Regency Intrastate Enhancement Project is a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to access new sources of supply and markets. We began planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005.

      The total cost of this project is expected to be approximately $140 million, which includes the expansion of our existing Regency Intrastate Pipeline system and an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system supported by approximately 9,500 horsepower of additional compression. The project has extended our transportation services into additional major producing fields in north Louisiana and has connected our system to additional interstate and intrastate pipelines in northeast Louisiana.

      The completion of the Regency Intrastate Enhancement Project enables us to provide transportation services from the three largest natural gas producing fields in Louisiana. Prior to the completion of the final phase of the project in December 2005, we were transporting approximately 265 MMcf/d under existing contracts, including 65 MMcf/d attributable to the completion of the first two phases of the project. Additionally, we have signed definitive agreements for 249 MMcf/d of firm transportation and 156 MMcf/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining incremental transportation capacity of 130 MMcf/d resulting from the Regency Intrastate Enhancement Project.

Business Strategies

      Our management team is dedicated to increasing the amount of cash available for distribution to each unit by executing the following strategies:

•  Implementing cost-effective organic growth opportunities;

•  Continuing to enhance profitability of our existing assets;

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•  Pursuing accretive acquisitions of complementary assets;

•  Continuing to reduce our exposure to commodity price risk; and

•  Improving our credit ratings.

Competitive Strengths

      We believe that we are well positioned to execute our strategies and to compete in the natural gas gathering, processing, marketing and transportation businesses, based on the following competitive strengths:

•  We have a significant market presence in major natural gas supply areas;

•  Our recently completed Regency Intrastate Enhancement Project provides us with the opportunity to increase significantly our fee-based transportation throughput and cash flow;

•  We have the financial flexibility to pursue growth opportunities;

•  We have an experienced, knowledgeable management team with a proven track record of performance; and

•  We are affiliated with Hicks Muse, a leading private equity investment firm headquartered in Dallas, Texas. Our affiliation with Hicks Muse provides us with significant benefits, including access to a significant pool of operational, transactional and financial professionals, multiple sources of capital and increased exposure to acquisition opportunities.

Summary of Risk Factors

      An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please read carefully these and other risks under “Risk Factors.”

     Risks Related to Our Business

•  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner.

•  The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant risks that could cause actual results to differ materially from those forecasted.

•  If we do not receive the revenues we anticipate from the Regency Intrastate Enhancement Project, our cash flow and our ability to make cash distributions to you may be adversely affected.

•  Approximately 130 MMcf/d of the incremental capacity resulting from the completion of the Regency Intrastate Enhancement Project has not yet been contracted for. If we are unable to utilize the remaining incremental transportation capacity, our business and our operating results could be adversely affected.

•  Because of the natural decline in production from existing wells, our success depends on our ability to obtain new supplies of natural gas, which involves factors beyond our control. Any decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

•  We depend on certain key producers and other customers for a significant portion of our supply of natural gas. The loss of, or reduction in volumes from, any of these key producers or customers could adversely affect our business and operating results.

•  In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems. Accordingly, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to you.

3

•  Natural gas, NGL and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions to you.

•  In our gathering and processing operations, we purchase raw natural gas containing significant quantities of NGLs, process the raw natural gas and sell the processed gas and NGLs. If we are unsuccessful in balancing the purchase of raw natural gas with its component NGLs and our sales of pipeline quality gas and NGLs, our exposure to commodity price risks will increase.

•  Our results of operations and cash flow may be adversely affected by risks associated with our hedging activities and our hedging activities may limit potential gains.

Risks Inherent in an Investment in Us

•  The HMTF Investors will own a 62.7% limited partner interest in us and will control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to your detriment.

•  The HMTF Investors and their affiliates may directly compete with us.

•  Our reimbursement of our general partner’s fees and expenses will reduce our cash available for distribution to you.

•  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.

•  Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

•  Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

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

•  Control of our general partner may be transferred to a third party without unitholder consent.

•  You will experience immediate and substantial dilution of $18.11 per common unit.

•  We may issue an unlimited number of additional units without your approval, which would dilute your existing ownership interests.

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

•  Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

•  Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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 entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to you.

•  A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to you.

•  You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

•  Tax gain or loss on disposition of common units could be more or less than expected.

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

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

•  You may be subject to state and local taxes and tax return filing requirements.

Formation Transactions and Partnership Structure

      We are a Delaware limited partnership formed in September 2005 to own and operate Regency Gas Services LLC. Prior to this offering, Regency Gas Services LLC has been owned by the HMTF Investors. In connection with the consummation of this offering, Regency Gas Services LLC will be converted into a limited partnership named Regency Gas Services LP and will be contributed to us by the HMTF Investors in exchange for 5,353,896 common units, 19,103,896 subordinated units, the incentive distribution rights, a continuation of its 2% general partner interest in us, and a right to receive $197.0 million of proceeds from this offering for reimbursement of a corresponding amount of capital expenditures comprising most of the initial investment by the HMTF Investors in Regency Gas Services LLC. In addition, approximately $48.0 million in cash and accounts receivable will be distributed by Regency Gas Services LLC to the HMTF Investors prior to Regency Gas Services LLC being contributed to us and will be replenished with proceeds from the offering.

      At the closing of this offering and the related formation transactions:

•  we will issue 13,750,000 common units to the public in this offering, representing a 35.3% limited partnership interest in us;

•  the HMTF Investors will own 5,353,896 common units and 19,103,896 subordinated units, totaling an aggregate 62.7% limited partner interest in us;

•  the HMTF Investors will own all of the equity interests in our general partner, Regency GP LP;

•  Regency GP LP will own the 2% general partner interest in us as well as the incentive distribution rights;

•  we will own all of the ownership interests in Regency Gas Services LP, our operating partnership, and its operating subsidiaries, which will own and operate our assets;

•  we will pay $9.0 million to an affiliate of Hicks Muse as consideration for the termination of ten-year financial advisory and monitoring and oversight agreements between the affiliate of Hicks Muse and us. These agreements would have required us to pay to the affiliate of Hicks Muse certain management fees and transaction advisory fees in the future, which would decrease our cash available for distribution; and

•  we will enter into an omnibus agreement with Regency Acquisition LP, an affiliate of the HMTF Investors, pursuant to which Regency Acquisition LP will agree to indemnify us for certain environmental liabilities, tax liabilities and title and right-of-way defects occurring or existing before the closing.

      The diagram on the following page depicts our organization and ownership after giving effect to the offering and the related formation transactions.

5

Ownership of Regency Energy Partners LP

Public Common Units	35.3	%
HMTF Investors Common and Subordinated Units	62.7	%
General Partner	2.0	%
	100.0	%

6

Management of Regency Energy Partners

      Regency GP LP, our general partner, has direct responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, Regency GP LLC, is ultimately responsible for the business and operations of Regency GP LP, and will conduct our business and operations, and the board of directors and officers of Regency GP LLC will make decisions on our behalf. The senior executives who currently manage our business will continue to manage us. Neither our general partner, nor any of its affiliates will receive any management fee or other compensation in connection with the management of our business, but they will be entitled to reimbursement for all direct and indirect expenses they incur on our behalf.

      Neither our general partner nor the board of directors of Regency GP LLC will be elected by our unitholders. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect the directors of Regency GP LLC. References herein to the officers or directors of our general partner refer to the officers and directors of Regency GP LLC.

      Hicks Muse, which will control our general partner, is headquartered in Dallas, Texas and is a leading private equity investment firm with total funds managed of over $10 billion. Since the firm’s founding in 1989, Hicks Muse’s experienced investment team has completed more than 400 transactions with a total value in excess of $50 billion.

Principal Executive Offices and Internet Address

      Our principal executive offices are located at 1700 Pacific, Suite 2900, Dallas, Texas 75201 and our telephone number is (214) 750-1771. Our website is located at www.regencyenergy.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

7

The Offering

Common units offered to the public	13,750,000 common units.
	15,812,500 common units, if the underwriters exercise their option to purchase additional units in full.
Units outstanding after this offering	19,103,896 common units and 19,103,896 subordinated units, representing 49.0% and 49.0%, respectively, limited partner interests in us.
Use of proceeds	We intend to use the net proceeds of approximately $257.0 million from this offering, after deducting underwriting discounts, fees and commissions but before estimated expenses:
	• to replenish all, or approximately $48.0 million, of the working capital, or 18.7% of net proceeds, $37.0 million of which will be used to repay working capital borrowings under the revolving portion of our second amended and restated credit facility, that will be distributed to the HMTF Investors by Regency Gas Services LLC immediately prior to consummation of this offering;
	• to distribute approximately $197.0 million, or 76.6% of net proceeds, to the HMTF Investors for reimbursement of capital expenditures comprising most of the initial investment by the HMTF Investors in Regency Gas Services LLC;
	• to pay $9.0 million, or 3.5% of net proceeds, to an affiliate of Hicks Muse as consideration for the termination of ten-year financial advisory and monitoring and oversight agreements between the affiliate of Hicks Muse and us; and
	• to pay approximately $3.0 million, or 1.2% of net proceeds, for expenses associated with the offering and related formation transactions.
	The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem an equal number of common units from the HMTF Investors.
Cash distributions	We intend to make minimum quarterly distributions of $0.35 per unit to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner. In general, we will pay any cash distribution we make each quarter in the following manner:
	• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.35 plus any cash distribution arrearages from prior quarters;
	• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.35; and
	• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4025.
	If cash distributions exceed $0.4025 per unit in any quarter, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to

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	these distributions as “incentive distributions.” Please read “How We Make Cash Distributions.”
	Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B. The amount of available cash may be greater than or less than the amount required to pay the minimum quarterly distribution per common unit.
	The amount of estimated cash available for distribution generated during 2004 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only 22.1% of the minimum quarterly distribution on the subordinated units. The amount of estimated cash available for distribution generated during the twelve months ended September 30, 2005 would have allowed us to pay all of the minimum quarterly distribution on our common units and 11.6% of the minimum quarterly distribution on our subordinated units. Please read “Cash Distribution Policy and Restrictions on Distributions.”
	We have included a forecast of our cash available for distribution for the twelve months ending December 31, 2006 in “Cash Distribution Policy and Restrictions on Distributions — Forecasted Cash Available for Distribution for the Twelve Months Ending December 31, 2006.” We believe, based on our financial forecast and related assumptions, that we will have sufficient available cash to enable us to pay the full minimum quarterly distribution of $0.35 on all of our common and subordinated units for the four quarters ending December 31, 2006.
Subordinated units	The HMTF Investors will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.35 per unit only after the common units have received the minimum quarterly distribution plus any cumulative arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid at least $1.40 on each outstanding unit and the corresponding distribution on the general partner’s 2% interest for any three consecutive four-quarter periods ending on or after December 31, 2008, but may end prior to December 31, 2008, if additional financial tests are met as described below.
	When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
Early conversion of subordinated units	If we have earned and paid at least $2.10 (150% of the annualized minimum quarterly distribution) on each outstanding

9

	unit for any four-quarter period ending on or after December 31, 2006, the subordinated units will convert into common units. Please read “How We Make Cash Distributions — Subordination Period.”
Issuance of additional units	We can issue an unlimited number of units without the consent of our unitholders. Please read “Risk Factors — We May Issue an Unlimited Number of Additional Units Without Your Approval, Which Would Dilute Your Existing Ownership Interest,” “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
Limited voting rights	Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or the directors of Regency GP LLC annually or otherwise. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 64.0% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights.”
Limited call right	If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.
Estimated ratio of taxable income to distributions	We estimate that, if you hold the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.40 per unit, we estimate that your allocable federal taxable income per year will be no more than $0.28 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”
Material tax consequences	For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”
Exchange listing	We have been approved to list our common units on the Nasdaq National Market under the symbol “RGNC.”

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Summary Historical and Pro Forma Financial and Operating Data

      The following table shows summary historical financial and operating data of our predecessors, Regency LLC Predecessor and Regency Gas Services LLC, and unaudited pro forma financial data of Regency Energy Partners LP for the periods and as of the dates indicated. Our historical results of operations for the periods presented below may not be comparable, either from period to period or going forward, for the following reasons:

•  Regency Gas Services LLC was formed on April 2, 2003 and commenced operations on June 2, 2003 with the acquisition of certain natural gas gathering, processing and transportation assets from subsidiaries of El Paso Corporation. As a result, we do not have any financial results for periods prior to April 2, 2003 and our results of operations for the period ended December 31, 2003 includes only seven months of financial results.

•  On March 1, 2004, Regency Gas Services LLC acquired certain natural gas gathering and processing assets from Duke Energy Field Services, LP. As a result, our historical financial results for the periods prior to March 1, 2004 do not include the financial results from the operation of these assets.

•  In connection with the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004, the purchase price was “pushed-down” to the financial statements of Regency Gas Services LLC. As a result of this “push-down” accounting, the book basis of our assets was increased to reflect the purchase price, which had the effect of increasing our depreciation expense. Also, the increased amount of debt we incurred in connection with the acquisition increased our interest expense subsequent to December 1, 2004.

•  After our acquisition by the HMTF Investors, we initiated a risk management program comprised of commodity swaps and crude oil puts that we accounted for using mark-to-market accounting. These amounts are included in unrealized/realized gain(loss) from risk management activities.

•  In response to transmission capacity constraints in north Louisiana, we significantly expanded and extended our pipeline assets in this region, increasing our capacity to 800 MMcf/d from 200 MMcf/d and increasing the length of the pipeline to 280 miles from 200 miles. The total cost of the project, which was completed in December 2005, is expected to be approximately $140 million.

      We refer to Regency Gas Services LLC as “Regency LLC Predecessor” for periods prior to the acquisition by the HMTF Investors.

      The summary historical financial data for the period from acquisition date (December 1, 2004) to December 31, 2004 are derived from the audited financial statements of Regency Gas Services LLC. The summary historical financial data for the period from January 1, 2004 to November 30, 2004 and the period from inception (April 2, 2003) to December 31, 2003 are derived from the audited financial statements of Regency LLC Predecessor. The summary historical financial data for the nine months ended September 30, 2004 were derived from the unaudited financial statements of Regency LLC Predecessor, and the summary historical financial data for the nine months ended September 30, 2005 were derived from the unaudited financial statements of Regency Gas Services LLC.

      The summary pro forma financial data for the nine months ended September 30, 2005 and for the year ended December 31, 2004 are derived from the unaudited pro forma financial statements of Regency Energy Partners LP. The pro forma adjustments have been prepared as if this offering and the related transactions had taken place on September 30, 2005, in the case of the pro forma balance sheet or as of January 1, 2004, in the case of the pro forma statements of operations for the year ended December 31, 2004 and the nine months ended September 30, 2005. The pro forma statement of operations for the year ended December 31, 2004 has also been adjusted to give effect to the impact on our reported results of the acquisition of Regency Gas Services LLC by the HMTF Investors and our purchase of assets from Duke Energy Field Services as if such transactions occurred on January 1, 2004.

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      The following table includes the non-GAAP financial measures of EBITDA and total segment margin. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. We define total segment margin as total revenue, including service fees, less cost of gas and liquids and other cost of sales. For a reconciliation of EBITDA and total segment margin to their most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States), please read “— Non-GAAP Financial Measures.”

													Regency Gas Services LLC
				Regency LLC Predecessor
													Period from						Regency Energy Partners LP
													Acquisition						Unaudited Pro Forma
				Period from			Period from			Nine Months			Date			Nine Months
				Inception			January 1,			Ended			(December 1,			Ended						Nine Months
				(April 2, 2003) to			2004 to			September 30,			2004) to			September 30,			Year Ended			Ended
				December 31,			November 30,			2004			December 31,			2005			December 31,			September 30,
				2003			2004			(unaudited)			2004			(unaudited)			2004			2005
				($ in thousands except per unit data)
Statement of Operations Data:
Total revenue(1)				$	186,533		$	432,321		$	339,106		$	47,841		$	434,566		$	501,895		$	434,566
Total expense
	Total cost of sales				163,461			362,762			285,951			40,986			386,892			421,658			386,892
	Operating expenses				7,012			17,786			13,651			1,819			15,495			20,947			15,495
	General and administrative				2,651			6,571			5,323			638			9,571			9,742			10,614
	Transaction expenses				724			7,003			—			—			—			—			—
	Depreciation and amortization				4,324			10,129			8,146			1,613			15,718			20,314			15,718
			Total operating expenses		178,172			404,251			313,071			45,056			427,676			472,661			428,719
Operating income					8,361			28,070			26,035			2,785			6,890			29,234			5,847
Other income and deductions
	Interest expense, net				(2,392	)		(5,097	)		(4,139	)		(1,335	)		(12,684	)		(9,193	)		(10,528	)
	Loss on debt refinancing				—			(3,022	)		(1,406	)		—			(7,724	)		—			(7,724	)
	Other income and deductions, net				205			186			67			14			226			200			226
			Total other income and deductions		(2,187	)		(7,933	)		(5,478	)		(1,321	)		(20,182	)		(8,993	)		(18,026	)
Net income (loss) from continuing operations					6,174			20,137			20,557			1,464			(13,292	)		20,241			(12,179	)
Discontinued operations					—			(121	)		(14	)		—			732			—			—
Net income (loss)				$	6,174		$	20,016		$	20,543		$	1,464		$	(12,560	)	$	20,241		$	(12,179	)
General partner interest in pro forma net income (loss)																			$	405		$	(244	)
Limited partner interest in pro forma net income (loss)																			$	19,836		$	(11,935	)
Pro forma net income per limited partner unit																			$	0.52		$	(0.31	)
Balance Sheet Data (at period end):
Property, plant and equipment, net				$	118,986								$	328,348		$	404,446					$	404,446
Total assets					164,330									486,489			598,511						598,511
Long-term debt					66,600									250,000			308,350						308,350
Net equity					59,856									176,964			157,180						157,180
Cash Flow Data:
Net cash flows provided by (used in):
	Operating activities			$	6,494		$	32,401		$	29,501		$	(4,930	)	$	21,354
	Investing activities				(123,165	)		(84,721	)		(81,151	)		(129,947	)		(81,326	)
	Financing activities				118,245			56,380			53,880			132,515			70,780
Other Financial Data:
Total segment margin(1)				$	23,072		$	69,559		$	53,155		$	6,855		$	47,674		$	80,237		$	47,674
EBITDA(1)					12,890			35,242			32,828			4,412			15,842			49,748			14,067
Maintenance capital expenditures					1,633			5,548			4,226			358			4,730			5,906			4,730
Segment Financial and Operating Data:
	Gathering and Processing Segment:
		Financial data:
			Segment margin(1)	$	18,805		$	61,347		$	46,282		$	6,247		$	37,571		$	71,417		$	37,571
			Operating expenses		6,131			16,230			12,444			1,655			14,231			19,227			14,231
		Operating data:
			Natural gas throughput (MMcf/d)		199			279			272			289			284			299			284
			NGL gross production (Bbls/d)		9,434			14,487			13,841			15,675			14,824			15,726			14,824
	Transportation Segment:
		Financial data:
			Segment margin	$	4,268		$	8,212		$	6,873		$	608		$	10,103		$	8,820		$	10,103
			Operating expenses		881			1,556			1,207			164			1,264			1,720			1,264
		Operating data:
			Throughput (MMcf/d)		197			179			177			150			232			176			232

(1)  Includes $0.3 million of unrealized gains on risk management activities for the one month ended December 31, 2004 and $12.7 million of net unrealized losses on risk management activities for the nine months ended September 30, 2005.

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Non-GAAP Financial Measures

      We include in this prospectus the following non-GAAP financial measures: EBITDA and total segment margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

      We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•  financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•  the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partner;

•  our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

•  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

      EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

      EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA, to evaluate our performance.

      We define total segment margin as total revenues, including service fees, less cost of gas and liquids and other cost of sales. Total segment margin is included as a supplemental disclosure because it is a primary performance measure used by our management as it represents the results of product sales, service fee revenues and product purchases, a key component of our operations. We believe segment margin is an important measure because it is directly related to our volumes and commodity price changes. Operating expenses are a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin. As an indicator of our operating performance, total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate total segment margin in the same manner.

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      The following table presents a reconciliation of EBITDA and total segment margin to the most directly comparable GAAP financial measures, net income and net cash flows provided by (used in) operating activities on a historical basis and, as applicable, a pro forma basis for each of the periods indicated.

												Regency Gas Services LLC
			Regency LLC
			Predecessor
												Period from						Regency Energy Partners LP
												Acquisition						Unaudited Pro Forma
			Period from			Period from			Nine Months			Date			Nine Months
			Inception			January 1,			Ended			(December 1,			Ended						Nine Months
			(April 2, 2003) to			2004 to			September 30,			2004) to			September 30,			Year Ended			Ended
			December 31,			November 30,			2004			December 31,			2005			December 31,			September 30,
			2003			2004			(unaudited)			2004			(unaudited)			2004			2005
			($ in thousands)
Reconciliation of “EBITDA” to net cash flows provided by (used in) operating activities and net income (loss)
Net cash flows provided by (used in) operating activities			$	6,494		$	32,401		$	29,501		$	(4,930	)	$	21,354
	Add (deduct):
		Depreciation and amortization		(4,658	)		(10,461	)		(8,425	)		(1,745	)		(16,565	)
		Loss on debt refinancing		—			(3,022	)		(1,406	)					(7,724	)
		Risk management portfolio value changes		—			—			(34	)		322			(13,590	)
		Gain on the sale of Regency Gas Treating LP assets		—			—			—			—			626
		Gain on the sale of NGL line pack		—			—			—			—			628
		Accounts receivable		31,390			20,408			6,807			(2,583	)		35,074
		Advances to affiliates		576			(576	)		—			—			—
		Other current assets		1,070			1,169			1,876			2,430			1,611
		Accounts payable and accrued liabilities		(26,880	)		(18,122	)		(7,400	)		155			(34,970	)
		Accrued taxes payable		(906	)		(1,475	)		(664	)		921			(1,212	)
		Interest payable		(143	)		(398	)		143			541			(81	)
		Distributions payable		(68	)		69			69			—			—
		Other current liabilities		(706	)		(173	)		76			(293	)		734
		Other assets		5			196			—			6,646			1,555
Net income (loss)			$	6,174		$	20,016		$	20,543		$	1,464		$	(12,560	)	$	20,241		$	(12,179	)
	Add:
		Interest expense, net		2,392			5,097			4,139			1,335			12,684			9,193			10,528
		Depreciation and amortization		4,324			10,129			8,146			1,613			15,718			20,314			15,718
EBITDA(1)			$	12,890		$	35,242		$	32,828		$	4,412		$	15,842		$	49,748		$	14,067
Reconciliation of net income (loss) to total segment margin
Net income (loss)			$	6,174		$	20,016		$	20,543		$	1,464		$	(12,560	)	$	20,241		$	(12,179	)
	Add (deduct):
		Operating expenses		7,012			17,786			13,651			1,819			15,495			20,947			15,495
		General and administrative		2,651			6,571			5,323			638			9,571			9,742			10,614
		Transaction expenses		724			7,003			—			—			—			—			—
		Depreciation and amortization		4,324			10,129			8,146			1,613			15,718			20,314			15,718
		Interest expense, net		2,392			5,097			4,139			1,335			12,684			9,193			10,528
		Loss on debt refinancing		—			3,022			1,406			—			7,724			—			7,724
		Other income and deductions, net		(205	)		(186	)		(67	)		(14	)		(226	)		(200	)		(226	)
		Discontinued operations		—			121			14			—			(732	)		—			—
Total segment margin(1)			$	23,072		$	69,559		$	53,155		$	6,855		$	47,674		$	80,237		$	47,674

(1)  Includes $0.3 million of unrealized gains on risk management activities for the one month ended December 31, 2004 and $12.7 million of net unrealized losses on risk management activities for the nine months ended September 30, 2005.

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RISK FACTORS

      Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

      If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner.

      We may not have sufficient available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•  the fees we charge and the margins we realize for our services and sales;

•  the prices of, level of production of, and demand for natural gas and NGLs;

•  the volumes of natural gas we gather, process and transport;

•  the level of our operating costs, including reimbursement of fees and expenses of our general partner; and

•  prevailing economic conditions.

      In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•  our debt service requirements;

•  fluctuations in our working capital needs;

•  our ability to borrow funds and access capital markets;

•  restrictions contained in our debt agreements;

•  the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects such as our Regency Intrastate Enhancement Project;

•  the cost of acquisitions, if any; and

•  the amount of cash reserves established by our general partner.

      You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

      For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

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The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant risks that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on the common units or subordinated units and the market price of the common units may decline materially.

      The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and cash flows for the twelve months ending December 31, 2006. The financial forecast has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks, including those discussed below, that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on the common units or subordinated units and the market price of the common units may decline materially.

      The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after this offering is approximately $54.6 million, which does not include $0.48 million of distributions on the unit distribution rights associated with the 340,000 restricted units that we expect to grant under our long term incentive plan upon the consummation of this offering. Our forecast regarding our ability to pay the minimum quarterly distributions for 2006 is predicated on, among other things, our receipt of anticipated revenues from our Regency Intrastate Enhancement Project, which is the subject of the next risk factor. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2004 and for the twelve-month period ended September 30, 2005, and for a forecast of our ability to pay the full minimum quarterly distributions on the common and subordinated units and the 2% general partner interest for the twelve-month period ending December 31, 2006, please read “Cash Distribution Policy and Restrictions on Distributions.”

If we do not receive the revenues we anticipate from the Regency Intrastate Enhancement Project, our cash flow and our ability to make cash distributions to you may be adversely affected.

      Our forecast regarding our ability to pay the minimum quarterly distributions for 2006 assumes, among other things, the generation of revenues contemplated by the gas transportation contracts relating to our Regency Intrastate Enhancement Project.

      Our forecast of 2006 distributions also assumes the generation of the revenues contemplated by the contracts that we have entered into with our customers relating to the transportation of gas on our Regency Intrastate Pipeline at the time the project has been completed. If any of the following were to occur, our forecast of these revenues would be adversely affected:

•  we are unable to perform the requisite transportation services for any reason, including a delay in the completion of interconnections or the transportation of expected volumes of natural gas on the project,

•  in the case of interruptible transportation services, our customers fail to utilize our services in whole or in part, or

•  our customers fail to pay for our services for any reason, including financial distress.

      Approximately 130 MMcf/d of the incremental capacity resulting from the completion of the Regency Intrastate Enhancement Project has not yet been contracted for. If we are unable to utilize the remaining incremental transportation capacity, our business and our operating results could be adversely affected.

      We have agreed to provide natural gas transportation services to natural gas producers in the area upon completion of the Regency Intrastate Enhancement Project, which increased our capacity on the Regency Intrastate Pipeline from 200 MMcf/d to 800 MMcf/d. We are currently transporting approximately 265 MMcf/d under existing contracts, including 65 MMcf/d attributable to the completion of the first two phases of the project. Additionally we have signed definitive agreements for 249 MMcf/d

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of firm transportation and 156 MMcf/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining incremental transportation capacity of 130 MMcf/d resulting from the Regency Intrastate Enhancement Project; however, this incremental capacity is not currently under contract. If we are unable to contract for the remaining incremental transportation capacity, our business and our operating results could be adversely affected.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new supplies of natural gas, which involves factors beyond our control. Any decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

      Our gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells that supply our systems and from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets include: the level of successful drilling activity near these systems and our ability to compete with other gathering and processing companies for volumes from successful new wells.

      The level of natural gas drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. Currently, natural gas prices are high in relation to historical prices. For example, the twelve-month average of NYMEX daily settlement price of natural gas increased from $6.18 per MMBtu as of December 31, 2004 to $9.02 per MMBtu as of December 31, 2005. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and processing facilities and pipeline transportation systems, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if natural gas reserves were discovered in areas served by our assets, producers may choose not to develop those reserves. If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

We depend on certain key producers and other customers for a significant portion of our supply of natural gas. The loss of, or reduction in volumes from, any of these key producers or customers could adversely affect our business and operating results.

      We rely on a limited number of producers and other customers for a significant portion of our natural gas supplies. Our three largest suppliers of natural gas for the year ended December 31, 2004, Cohort Energy Company, KCS Resources, Inc. and Chesapeake Energy Marketing, Inc., accounted for approximately 33.3% of our total natural gas purchases. These suppliers sell natural gas under a number of contracts, including two contracts with Cohort Energy Company, twelve contracts with KCS Resources, Inc. and nine contracts with Chesapeake Energy Marketing, Inc. All of these contracts have terms that are either month-to-month or year-to-year. As these contracts expire, we will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. We may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

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In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems. Accordingly, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to you.

      In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our gathering systems could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

Natural gas, NGLs and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions to you.

      We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. In 2005, the same index ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2004 ranged from a high of $56.37 per barrel to a low of $32.49 per barrel. In 2005, the same index ranged from a high of $69.91 per barrel to a low of $42.16 per barrel. 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:

•  the impact of weather on the demand for oil and natural gas;

•  the level of domestic oil and natural gas production;

•  the availability of imported oil and natural gas;

•  actions taken by foreign oil and gas producing nations;

•  the availability of local, intrastate and interstate transportation systems;

•  the availability and marketing of competitive fuels;

•  the impact of energy conservation efforts; and

•  the extent of governmental regulation and taxation.

      Our natural gas gathering and processing businesses operate under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality gas and NGLs or NGL products resulting from our processing activities. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, under keep-whole arrangements it is more profitable for us to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and

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a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. For a detailed discussion of these arrangements, please read “Business — Our Contracts.”

In our gathering and processing operations, we purchase raw natural gas containing significant quantities of NGLs, process the raw natural gas and sell the processed gas and NGLs. If we are unsuccessful in balancing the purchase of raw natural gas with its component NGLs and our sales of pipeline quality gas and NGLs, our exposure to commodity price risks will increase.

      We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering and processing systems and our transportation pipeline for resale to third parties, including natural gas marketers and utilities. We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or deliver in excess of contracted volumes, a purchaser could purchase less than contracted volumes, or the price of natural gas could vary between the regions in which we operate. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating results.

Our results of operations and cash flow may be adversely affected by risks associated with our hedging activities and our hedging activities may limit potential gains.

      In performing our functions in the Gathering and Processing segment, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. As a result of the volatility of NGL and other commodity prices in recent years, in December 2004, we initiated a plan to hedge a significant percentage of our total segment margin for the years 2005 to 2007. Under this plan, we executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options. (Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil.) As a result, we have hedged approximately 95% of our expected exposure to NGL prices in 2006, and approximately 75% in 2007. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. Also, we may seek to limit our exposure to changes in interest rates by using financial derivative instruments and other hedging mechanisms from time to time. Our hedging transactions are intended to reduce our exposure to downward movements in NGL prices. In exchange for this reduction in exposure, however, these transactions limit our potential gains if NGL prices rise over the price established by the hedging arrangements. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect, or our hedging policies and procedures are not followed or do not work as planned.

To the extent that we intend to grow internally through construction of new, or modification of existing, facilities, we may not be able to manage that growth effectively which could decrease our cash flow and our cash available for distribution.

      A principal focus of our strategy is to continue to grow by expanding our business both internally and through acquisitions. Our ability to grow internally will depend on a number of factors, some of which will be beyond our control.

      In general, the construction of additions or modifications to our existing systems, and the construction of new midstream assets involve, as indicated above, numerous regulatory, environmental, political and legal uncertainties beyond our control. Any project that we undertake may not be completed on schedule at budgeted cost or at all. Construction may occur over an extended period, and we are not likely to receive a material increase in revenues related to such project until it is completed. Moreover, our revenues may not increase immediately upon its completion because the anticipated growth in gas production that the project was intended to capture does not materialize, our estimates of the growth in production prove inaccurate or for other reasons. For any of these reasons, newly constructed or modified

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midstream facilities may not generate our expected investment return and that, in turn, could adversely affect our results of operations and our ability to make cash distributions to you.

      In addition, our ability to undertake to grow in this fashion will depend on our ability to finance the construction or modification project and on our ability to hire, train and retain qualified personnel to manage and operate these facilities when completed.

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

      Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash per unit generated from operations. Factors affecting our ability to do so include our abilities:

•  To identify businesses engaged in managing, operating or owning gathering, compression, processing and pipeline assets for acquisitions and joint ventures;

•  to obtain required financing for acquisitions and joint ventures;

•  to outbid competitors for acquisition prospects;

•  to analyze acquisition and joint venture prospects successfully from both an operational and financial viewpoint;

•  to consummate acquisitions and joint ventures;

•  to integrate acquired businesses and assets with our existing operations and to subject them to our operating and financial systems and controls; and

•  to hire, train and retain qualified personnel to manage and operate our expanded business.

In addition, even though we expect an acquisition to be accretive, it may not be.

      Any acquisition involves potential risks, including among others the following:

•  Mistaken assumptions regarding revenues and costs, including synergies;

•  the assumption of unknown liabilities;

•  limitations on rights to indemnity from sellers;

•  the diversion of management’s attention from other business concerns;

•  unforeseen difficulties in operating in new geographic areas; and

•  customer or key employee losses at the acquired business.

      Our capitalization and results of operations may change significantly if we consummate any acquisitions, and you will not have the opportunity to evaluate the economic, financial or other relevant information that we will consider in determining to make those acquisitions.

      Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of midstream assets by large industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

Because we distribute all of our available cash to our unitholders, our future growth may be limited.

      Since we will distribute all of our available cash to our unitholders, we will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant internal organic growth or acquisitions. If we are unable to obtain adequate financing from these sources, our ability to grow will be limited.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

      We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas than we do. In addition, our customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using ours. Similarly, competitors may

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establish new connections with pipeline systems that would create additional competition for services we provide to our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

Restrictions in our credit facility limit our ability to make distributions to you and our ability to capitalize on acquisitions and other business opportunities.

      Our bank credit facility prohibits us from making cash distributions during an event of default or if the payment of a distribution would cause an event of default. Our credit facility, as amended, allows us to make distributions as long as we are in compliance with the covenants in this agreement. In addition, it contains various covenants limiting our ability to incur indebtedness, to grant liens, and to engage in transactions with affiliates, as well as others requiring us to maintain certain financial ratios and tests. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repay this debt upon the occurrence of specified events involving a change of control of our general partner. Any subsequent refinancing of our current debt or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements.”

We will have a significant amount of debt that may limit our ability to grow.

      Upon completion of this offering, we expect our total outstanding long-term indebtedness to be approximately $370 million under our credit facility. Our leverage and various limitations in our credit facility and our lack of an investment grade rating may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current debt or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Capital Requirements” and “— Liquidity and Capital Resources.”

Increases in interest rates, which have recently experienced record lows, could adversely impact our unit price and our ability to issue additional equity, make acquisitions, reduce debt or for other purposes.

      The credit markets recently have experienced 50-year record lows in interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Upon completion of this offering, we expect our quarterly interest payments to range between $6.1 and $6.5 million. An increase of 100 basis points in the LIBOR rate would increase this quarterly payment by approximately $0.4 million. Additionally, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price for our units will be affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and our ability to issue additional equity, make acquisitions, reduce debt or for other purposes.

If third-party pipelines interconnected to our processing plants become unavailable to transport NGLs, our cash flow and cash available for distribution could be adversely affected.

      We depend upon third party pipelines that provide delivery options to and from our processing plants for the benefit of our customers. For example:

•  all of the NGLs produced at our north Louisiana system are transported to Mont Belvieu on the Black Lake Pipeline, which is owned by BP Energy Company and Duke Energy Field Services;

•  all of the NGLs produced at the Waha processing plant are transported to Mont Belvieu by use of Louis Dreyfus’ pipeline and ExxonMobil Corporation’s NGL pipeline; and

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•  all of the NGLs produced at our mid-continent processing plants are transported to the Conway Hub in Kansas by ONEOK Hydrocarbon Southwest L.L.C.’s NGL pipeline.

      If any of these pipelines become unavailable to transport the NGLs produced at our related processing plants, we would be required to find alternative means to transport the NGLs out of our processing plants, which could increase our costs, reduce the revenues we might obtain from the sale of NGLs or reduce our ability to process natural gas at these plants. For example, Hurricane Rita disrupted the operations of NGL pipelines and fractionators in the Houston, Texas area. As a result of these disruptions, we were forced temporarily to curtail certain of our producers in the west Texas region for approximately four days and to operate our north Louisiana processing assets in a reduced recovery mode for six days.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

      We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. For example, in January 2005, one of our customers filed for Chapter 11 reorganization under U.S. bankruptcy law although that customer has since emerged from bankruptcy court protection. Any material nonpayment or nonperformance by this customer or our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

      Our operations are subject to the many hazards inherent in the gathering, processing and transportation of natural gas and NGLs, including:

•  damage to our gathering and processing facilities, pipelines, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;

•  inadvertent damage from construction and farm equipment;

•  leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of measurement equipment or facilities at receipt or delivery points;

•  fires and explosions;

•  weather related hazards, such as hurricanes; and

•  other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

      These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not insured against all environmental events that might occur. If a significant accident or event occurs that is not insured or fully insured, it could adversely affect our operations and financial condition.

Due to our lack of asset diversification, adverse developments in our midstream operations would reduce our ability to make distributions to our unitholders.

      We rely exclusively on the revenues generated from our midstream energy business, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to our lack of diversification in asset type, an adverse development in this business would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

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Failure of the gas that we ship on our Regency Intrastate Pipeline to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

      The markets to which the shippers on our Regency Intrastate Pipeline ship natural gas include interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the total mix of natural gas shipped by the shippers on our pipeline fails to meet the specifications of a particular interstate pipeline, that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, we may be required to find alternative markets for that gas or to shut-in the producers of the non-conforming gas, potentially reducing our throughput volumes or revenues. Please see “Business — Transportation Operations — Interstate Pipeline Specifications.”

Terrorist attacks, the threat of terrorist attacks, continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

      The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas and NGLs and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

      Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

      We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for specified periods of time. Many of these rights-of-way are perpetual in duration; others have terms ranging from five to ten years. Many are subject to rights of reversion in the case of non-utilization for periods ranging from one to three years. In addition, some of our processing facilities are located on leased premises. Our loss of these rights, through our inability to renew right-of-way contracts or leases or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.

      In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. If the cost of obtaining new rights-of-way increases, then our cash flows and growth opportunities could be adversely affected.

A successful challenge to the rates we charge on Regency Intrastate Pipeline may reduce the amount of cash we generate.

      To the extent our Regency Intrastate Pipeline transports natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to regulation by the Federal Energy Regulatory Commission, or FERC, pursuant to Section 311 of the Natural Gas Policy Act of 1978, or NGPA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and the FERC is required to approve the terms and conditions of the service. Rates established pursuant to Section 311 are generally analogous to the cost based rates FERC deems “just and reasonable” for interstate pipelines under the Natural Gas Act or NGA. FERC may therefore apply its NGA policies to determine costs that can be included in cost of service used to

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establish Section 311 rates. These rate policies include the new FERC policy on income tax allowance that permits interstate pipelines to include, as part of the cost of service, a full income tax allowance for all entities owning the utility asset provided such entities or individuals are subject to an actual or potential tax liability. If the Section 311 rates presently approved for Regency through May 2008 are successfully challenged in a complaint or after such date the FERC disallows the inclusion of costs in the cost of service, changes its regulations or policies, or establishes more onerous terms and conditions applicable to Section 311 service, this may adversely affect our business. Any reduction in our rates could have an adverse effect on our business, results of operations, financial condition and ability to pay distributions to you.

A change in the characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

      Our natural gas gathering and intrastate transportation operations are generally exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive regulatory policies. We cannot assure you, however, 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. In addition, the distinction between FERC-regulated transmission service and federally unregulated gathering services is the subject of regular litigation at FERC and the courts and of policy discussions at FERC, so, in such circumstances, the classification and regulation of some of our gathering facilities or our intrastate transportation pipeline may be subject to change based on future determinations by FERC, and the courts or Congress. Such a change could result in increased regulation by FERC.

      Other state and local regulations also affect our business. Our gathering lines are subject to ratable take and common purchaser statutes in states in which we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or 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 restrict 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. States in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Please read “Business — Regulation.”

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

      Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the discharge of waste from our facilities and (3) the Comprehensive Environmental, Response Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal.

      In November 2005, we settled with the Texas Commission on Environmental Quality, or TCEQ, a notice of enforcement relating to the operation of the Waha processing plant in 2001 before it was acquired by us. In connection with this settlement, we agreed to construct an acid reinjection well, in

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which we will reinject emitted gases from the plant at a cost of $3.5 million. Please read “Business — Regulation.”

      In addition, in March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent us a notice of violation alleging that we are operating our Mocane processing plant in violation of specified national air quality standards. While we believe that the basis for these allegations is inapplicable to the Mocane plant, if they ultimately prove to be valid we could be required to pay a penalty and to implement additional air emission controls at that plant.

      Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the Clean Air Act, RCRA, CERCLA and the federal Water Pollution Control Act of 1972, also known as the Clean Water Act, and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

      There is inherent risk of the incurrence of environmental costs and liabilities in our business due to the necessity of handling of natural gas and other petroleum products, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. Please read “Business — Environmental Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Other Matters — Environmental.”

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud.

      Prior to this offering, we have been a private company and have not filed reports with the SEC. We will become subject to the public reporting requirements of the Securities Exchange Act of 1934 upon the completion of this offering. We produce our consolidated financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm to attest to, our internal control over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2007. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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Risks Inherent in an Investment in Us

The HMTF Investors will own a 62.7% limited partner interest in us and will control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to your detriment.

      Following the offering, the HMTF Investors will own a 62.7% limited partner interest in us and control our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner (who together own an economic interest in our general partner of 8.4%) have a fiduciary duty to manage our general partner in a manner beneficial to its owners, the HMTF Investors. Conflicts of interest may arise between the HMTF Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

•  neither our partnership agreement nor any other agreement requires the HMTF Investors or their affiliates to pursue a business strategy that favors us;

•  our general partner is allowed to take into account the interests of parties other than us, such as the HMTF Investors, in resolving conflicts of interest;

•  the HMTF Investors and their affiliates may engage in competition with us;

•  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, without the limitations, might constitute breaches of fiduciary duty;

•  our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;

•  our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or growth capital expenditure, which does not, which determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

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

•  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered 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;

•  our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

•  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.

      Please read “Conflicts of Interest and Fiduciary Duties.”

The HMTF Investors and their affiliates may compete directly with us.

      The HMTF Investors and their affiliates are not prohibited from owning assets or engaging in businesses that compete directly or independently with us. In addition, the HMTF Investors or their affiliates may acquire, construct or dispose of any additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct or dispose of those assets.

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Our reimbursement of our general partner’s expenses will reduce our cash available for distribution to you.

      Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.” The reimbursement of expenses of our general partner and its affiliates could adversely affect our ability to pay cash distributions to you.

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

•  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

•  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

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

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

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

      By purchasing a common unit, a common unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

      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 board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

      The unitholders will be unable initially to remove the general partner without its consent because the general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its affiliates will own 64.0% of the total of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

      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 our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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

      Our 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, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their ownership in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of Regency GP LLC with their own choices and to control the decisions taken by the board of directors and officers.

You will experience immediate and substantial dilution of $18.11 per common unit.

      The initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $1.89 per unit. You will incur immediate and substantial dilution of $18.11 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”

We may issue an unlimited number of additional units without your approval, which would dilute your existing ownership interest.

      Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional common units.

      The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•  our unitholders’ proportionate ownership interest in us will decrease;

•  the amount of cash available for distribution on each unit may decrease;

•  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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

•  the market price of the common units may decline.

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

      If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately 28.0% of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 64.0% of the common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

      A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. 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 other states in which we do business. In most states, a limited partner is only liable if he participates in the “control” of the business of the partnership. These statutes generally do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner 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 take other actions under our partnership agreement is found to constitute “control” of our business.

      For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

      Under certain circumstances, 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 you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the distribution, limited partners who received an impermissible 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. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

      Prior to the offering, there has been no public market for the common units. After the offering, there will be only 13,750,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

      The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•  our quarterly distributions;

•  our quarterly or annual earnings or those of other companies in our industry;

•  loss of a large customer;

•  announcements by us or our competitors of significant contracts or acquisitions;

•  changes in accounting standards, policies, guidance, interpretations or principles;

•  general economic conditions;

•  the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

•  future sales of our common units; and

•  other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a public company.

      We have no history operating as a public company. As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the stock exchanges and markets, have required changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a public company, we are required to have three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our public company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We are currently evaluating and monitoring developments with respect to these new rules, and we estimate the amount of additional costs we may incur will be $2.5 million annually.

Tax Risks to Common Unitholders

      In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to you.

      The anticipated after-tax economic benefit of an investment in the 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 tax matter affecting us.

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

      Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to you.

      We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other 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 some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

      Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.

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

      If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the

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amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you 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, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a regulated investment company, you should consult your tax advisor before investing in our common units.

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

      Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to 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 sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”

You may be subject to state and local taxes and tax return filing requirements.

      In addition to federal income taxes, you will likely 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, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in Texas, Oklahoma, Kansas, Louisiana, Arkansas and Colorado. Each of these states, other than Texas, currently imposes a personal income tax as well as an income tax on corporations and other entities. Texas imposes a franchise tax (which is based in part on net income) on corporations and limited liability companies. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

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USE OF PROCEEDS

      We expect to receive net proceeds of approximately $257.0 million from the sale of 13,750,000 common units offered by this prospectus, after deducting underwriting discounts, fees and commissions but before paying estimated offering expenses. Approximately $48.0 million of the net proceeds will be used to replenish our working capital as described below. We anticipate using the aggregate net proceeds of this offering:

•  To replenish all, or approximately $48.0 million, of the working capital, or 18.7% of net proceeds, $37.0 million of which will be used to repay working capital borrowings under the revolving portion of our second amended and restated credit facility, that will be distributed to the HMTF Investors by Regency Gas Services LLC immediately prior to consummation of this offering and the formation transactions;

•  to distribute approximately $197.0 million, or 76.6% of net proceeds, to the HMTF Investors for reimbursement of capital expenditures comprising most of the initial investment by the HMTF Investors in Regency Gas Service LLC;

•  to pay $9.0 million, or 3.5% of net proceeds, to an affiliate of Hicks Muse as consideration for the termination of ten-year financial advisory and monitoring and oversight agreements between the affiliate of Hicks Muse and us; and

•  to pay approximately $3.0 million, or 1.2% of net proceeds, of expenses associated with the offering and related formation transactions.

      The HMTF Investors will realize approximately $245.0 million as a result of distributions made by us in connection with this offering, including the $48.0 million of working capital distributed to them immediately prior to the consummation of this offering. This represents approximately 95.3% of the net proceeds from the offering. In addition, an affiliate of Hicks Muse will receive $9.0 million in connection with the termination of the financial advisory and monitoring and oversight agreements with us.

      Borrowings being repaid under the revolving portion of our second amended and restated credit facility were incurred temporarily to finance working capital. The revolving portion of our second amended and restated credit facility has an annual interest rate of 8.5% and matures on June 1, 2010. Affiliates of UBS Securities LLC, Wachovia Capital Markets, LLC and KeyBanc Capital Markets, a Division of McDonald Investments Inc., are lenders under our second amended and restated credit facility. Please read “Underwriting.”

      The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem an equal number of common units from the HMTF Investors.

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CAPITALIZATION

      The following table shows:

•  the cash and cash equivalents and the capitalization of Regency Gas Services LLC as of September 30, 2005; and

•  our pro forma cash and cash equivalents and capitalization as of September 30, 2005, as adjusted to reflect the offering.

      We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

				As of September 30, 2005
						Pro Forma
				Historical		As Adjusted
				(unaudited)
				($ in millions)
Cash and cash equivalents				$	14.1	$	24.6
Debt:
	Term loan facility				308.4		308.4
		Total debt(1)			308.4		308.4
Total member interest/partners’ capital:
	Member interest			$	157.2	$	—
	Common unitholders — public				—		55.4
	Common unitholders — HMTF Investors				—		21.6
	Subordinated units				—		77.0
	General partner interest				—		3.2
		Total member interest/ partners’ capital			157.2		157.2
			Total capitalization	$	465.6	$	465.6

(1)  Excludes $37.0 million related to borrowings under the revolving portion of our second amended and restated credit facility incurred for working capital purposes which will be repaid with the proceeds of the offering.

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DILUTION

      Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2005, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $73.7 million, or $2.92 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

Initial public offering price per common unit					$	20.00
	Pro forma net tangible book value per common unit before the offering(1)	$	2.92
	Decrease in net tangible book value per common unit attributable to purchasers in the offering		(1.03	)
Less: Pro forma net tangible book value per common unit after the offering(2)						1.89
Immediate dilution in tangible net book value per common unit to new investors					$	18.11

(1)	Determined by dividing the net tangible book value of the contributed assets and liabilities by the number of units (5,353,896 common units, 19,103,896 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 779,751 units) to be issued to the HMTF Investors for their contribution of assets and liabilities to Regency Energy Partners LP.
(2)	Determined by dividing our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering, by the total number of units to be outstanding after the offering (19,103,896 common units, 19,103,896 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 779,751 units).

      The following table sets forth the number of units that we will issue and the total consideration contributed to us by the HMTF Investors and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

		Units Acquired					Total Consideration
		Number		Percent			Amount			Percent
		(in thousands)					($ in thousands)
HMTF Investors(1)			25,238		64.7	%	$	(87,773	)		(46.9	)%
New investors			13,750		35.3			275,000			146.9	%
	Total		38,988		100.0	%	$	187,227			100.0	%

(1)  Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 5,353,896 common units and 19,103,896 subordinated units and a 2% general partner interest, which has a dilutive effect equivalent to 779,751 units. The net assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by the general partner and its affiliates, as of September 30, 2005, after giving effect to the application of the net proceeds of the offering is as follows:

		($ in thousands)
Book value of net assets contributed		$	157,180
Less: Distribution to the HMTF Investors from net proceeds of the offering			(196,953	)
Distribution of working capital			(48,000	)
	Total consideration	$	(87,773	)

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

      You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section.

General

      Our Cash Distribution Policy. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined generally to mean, for each fiscal quarter, cash generated from our businesses (which include the gathering, processing, marketing and transporting of natural gas) in excess of the amount our general partner determines is necessary or appropriate to provide for the conduct of our business, comply with applicable law, any of our debt instruments or other agreements or provide for future distributions to our unitholders for any one or more of the upcoming four quarters. Please read “How We Make Cash Distributions.”

      Rationale for Our Cash Distribution Policy. Because we believe we will generally finance capital investments from external financing sources, we believe that our investors are best served by distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to federal income tax.

      Limitations on Our Ability to Make Cash Distributions. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

•  Our distribution policy is subject to restrictions on distributions under our current credit facility. Specifically, the agreement related to our credit facility contains financial tests and covenants that we must satisfy in order to make distributions to our unitholders.

•  Our general partner has broad discretion to establish reserves for the prudent conduct of our business, and the establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.

•  Even if our cash distribution policy is not modified, the amount of distributions we pay and the decision to make any distribution is at the discretion of our general partner, taking into consideration the terms of our partnership agreement.

•  Although our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without approval of nonaffiliated common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. At the closing of this offering, the HMTF Investors will own a 62.7% limited partner interest in us.

•  We may lack sufficient cash to pay distributions to our unitholders due to increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses or working capital requirements.

•  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

      Our Cash Distribution Policy May Limit Our Ability to Grow. Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We expect that we will rely upon external financing sources, including bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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Cash Distributions

     Overview

      The amount of the minimum quarterly distribution is $0.35 per unit, or $1.40 per year. The amount of available cash from operating surplus, which we also refer to as cash available for distributions, needed to pay the minimum quarterly distribution on all of the common units and subordinated units and the 2% general partner interest to be outstanding immediately after this offering for one quarter and for four quarters will be approximately:

			Minimum Quarterly
			Distribution
	Number of Units		One Quarter		Four Quarters
			($ in thousands)
Common Units		19,103,896	$	6,686	$	26,745
Subordinated Units		19,103,896		6,686		26,745
2% General Partner Interest		779,751		273		1,092
Total		38,987,543	$	13,646	$	54,583	(1)

(1)  Excludes $0.48 million of distributions forecasted on the unit distribution rights associated with the 340,000 restricted units that we expect to grant under our long term incentive plan upon the consummation of this offering.

      The amounts in the table above will not change upon any exercise by the underwriters of their option to purchase additional common units.

Our Initial Distribution Rate

      Upon completion of this offering, our general partner will adopt a policy pursuant to which we will pay an initial quarterly distribution of $0.35 per unit for each complete quarter. Beginning with the quarter ending March 31, 2006, we will distribute, within 45 days after the end of each quarter, all of our available cash to unitholders of record on the applicable record date. We will adjust our first distribution for the period from the closing of the offering through March 31, 2006 based on the actual length of the period.

      During the subordination period, before we make any quarterly distributions to subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages from prior quarters. Please read “How We Make Cash Distributions— Subordination Period.” The amount of the minimum quarterly distribution is $0.35 per unit, or $1.40 per year. We cannot guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter.

      As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

      In the sections that follow, we present in detail the basis for our belief that we will be able to pay our minimum quarterly distribution through December 31, 2006. In those sections, we present three tables, consisting of:

•  Financial Forecast for the Twelve Months Ending December 31, 2006, in which we present our financial forecast of our results of operations and cash flows for the twelve months ended December 31, 2006 and the significant assumptions upon which this forecast is based;

•  Forecasted Cash Available for Distribution for the Twelve Months Ending December 31, 2006, in which we present the amount of available cash we forecast for the twelve months ending December 31, 2006 based on our financial forecast of our results of operations and cash flows for this period; and

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•  Pro Forma Available Cash for the Year Ended December 31, 2004 and Twelve Months Ended September 30, 2005, in which we present the amount of available cash we would have had for our fiscal year ended December 31, 2004, based on our pro forma financial statements that are included in this prospectus, and for the twelve months ended September 30, 2005.

Pro Forma Financial Information and Financial Forecast

      We present below a financial forecast of the expected results of operations and cash flows for Regency Energy Partners LP for the twelve months ending December 31, 2006. We also present the unaudited Combined Pro Forma results of operations and cash flows for the twelve month periods ended December 31, 2004 and September 30, 2005. Our financial forecast presents, to the best of our knowledge and belief, the expected results of operations and cash flows for Regency Energy Partners LP for the forecast period.

      Our financial forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2006. The assumptions disclosed in Note 3 to the financial forecast are those that we believe are significant to our financial forecast. We believe our actual results of operations and cash flows will approximate those reflected in our financial forecast, but we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy or at all.

      Our financial forecast is a forward-looking statement and should be read together with the historical financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The financial forecast has been prepared by and is the responsibility of our management. Neither Deloitte & Touche LLP, our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the forecasted financial information contained herein, nor have they expressed any opinion or given any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the forecasted financial information. Deloitte & Touche LLP reports included in this prospectus relate to historical financial information of Regency Gas Services LLC and Regency LLC Predecessor. Those reports do not extend to the financial forecast information and should not be read to do so.

      When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” elsewhere in this prospectus. Any of the risks discussed in this prospectus could cause our actual results of operations to vary significantly from the financial forecast.

      We are providing the financial forecast to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve month period ending December 31, 2006 at our stated initial distribution rate. Please read “Note 3. Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast.

      Actual payments of distributions on common units, subordinated units and the 2% general partner interest are expected to be $36.4 million for the twelve-month period ending December 31, 2006. This is the expected aggregate amount of cash distributions of approximately $0.23 for the first quarter of the period, assuming this offering closes on February 3, 2006, and $0.35 per unit per each additional quarter for the period. The fourth quarter distribution is not included because quarterly distributions are to be paid within 45 days after the close of each quarter. The distributions on common units, subordinated units and the 2% general partner interest related to the 2006 results, including the fourth quarter 2006 distribution, will be $50.1 million for the twelve months ended December 31, 2006. Please see “— Forecasted Cash Available for Distribution for the Twelve Months Ending December 31, 2006.”

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      We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update the financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, we caution you not to place undue reliance on this information.

      In the results of operations section of the unaudited combined pro forma results of operations and cash flows for the twelve months ended December 31, 2004, the results are presented to illustrate the assumed effects of the purchase of the west Texas assets, the HMTF transaction and this offering as if they had occurred on January 1, 2004. Also included are the effects of the restructuring and amendment of our credit facilities to consolidate our secured indebtedness under a single credit facility and to permit the reorganization and operation of our company as a publicly traded partnership. In the financing cash flow section of the unaudited combined pro forma results of operations and cash flows, we have excluded historical borrowings and member interest contributions for the west Texas acquisition, the HMTF transaction and this offering as the pro formas assume such borrowings and member interest contributions were outstanding at the beginning of the period.

      In the results of operations section of the unaudited combined pro forma results of operations and cash flows for the twelve months ended September 30, 2005, there was no adjustment required for the acquisition of the west Texas assets for the twelve months ended September 30, 2005 since the results of this transaction are already included in the historical consolidated financial statements. Adjustments have been made to include the effect of the HMTF transaction and this offering as if they had occurred prior to the commencement of the twelve month period ended September 30, 2005. In the financing cash flow section of the unaudited combined pro forma results of operations and cash flows, we have excluded historical borrowings and member interest contributions for the HMTF transaction and this offering as the pro formas assume such borrowings and member interest contributions were outstanding at the beginning of the period. The pro forma data included herein are not indicative of forecasted financial results nor do they represent comparable results of operations.

      The unaudited combined pro forma results of operations and cash flows are based on the audited Regency Gas Services LLC consolidated financial statements included elsewhere in this prospectus, as adjusted to illustrate the estimated pro forma effects of the transactions described above. The unaudited pro forma condensed financial statements should be read together with “Selected Historical and Selected Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Regency Gas Services LLC consolidated financial statements and the notes to those statements included elsewhere in this prospectus.

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REGENCY ENERGY PARTNERS LP

PRO FORMA AND FORECASTED RESULTS OF

OPERATIONS AND CASH FLOWS

		Combined Pro Forma (see Note 1)						Forecast
		Twelve Months			Twelve Months			Twelve Months
		Ended			Ended			Ended
		December 31,			September 30,			December 31,
		2004			2005			2006
		(unaudited)
		($ in thousands except per unit amounts)
Revenues:
Gathering and processing segment		$	374,317		$	417,917		$	483,623
Transportation segment			146,125			200,438			387,034
	Total revenues		520,442			618,355			870,657
Cost of sales:
Gathering and processing segment			302,901			359,034			405,971
Transportation segment			137,304			188,388			335,624
	Total cost of sales		440,205			547,422			741,595
Segment margin:
Gathering and processing segment			71,416			58,883			77,652
Transportation segment			8,821			12,050			51,410
	Total segment margin		80,237			70,933			129,062
Expenses:
Operating expense			20,947			21,449			22,155
General and administrative			9,742			12,976			17,730
Depreciation and amortization			20,314			21,302			29,083
	Total operating expenses		51,003			55,727			68,968
Operating income			29,234			15,206			60,094
Interest expense, net			(9,193	)		(12,102	)		(25,328	)
Loss on debt refinancing			—			(7,724	)		—
Other income and deductions, net			200			359			—
	Net income	$	20,241		$	(4,261	)	$	34,766
General partners’ interest in net income (loss)			405			(85	)		779
Limited partners’ interest in net income (loss)		$	19,836		$	(4,176	)	$	33,987
Basic and diluted net income (loss) per limited partner unit:		$	0.52		$	(0.11	)	$	0.89
Basic weighted average limited partner units outstanding:			38,207,792			38,207,792			38,207,792
Diluted weighted average limited partner units outstanding:			38,253,834			38,253,834			38,253,834

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REGENCY ENERGY PARTNERS LP

PRO FORMA AND FORECASTED RESULTS OF

OPERATIONS AND CASH FLOWS — (Continued)

		Combined Pro Forma (see Note 1)						Forecast
		Twelve Months			Twelve Months			Twelve Months
		Ended			Ended			Ended
		December 31,			September 30,			December 31,
		2004			2005			2006
		(unaudited)
		($ in thousands except per unit amounts)
	Net income	$	20,241		$	(4,261	)	$	34,766
Adjustments to reconcile net income to net operating cash flows:
	Depreciation and amortization		20,314			21,302			29,083
	Other non-cash items		(322	)		20,958			2,192
	Net operating cash flows		40,233			37,999			66,041
Maintenance capital expenditures			(5,906	)		(6,410	)		(6,000	)
Growth capital expenditures			(11,329	)		(87,926	)		(22,636	)
	Net investing cash flows		(17,235	)		(94,336	)		(28,636	)
Payment of debt under credit facility			(10,492	)		(6,199	)		—
Net proceeds from borrowings under credit facility (please read Note 3)			—			57,430			22,636
Partner contributions			—			15,000			—
Payments of distributions on common units, subordinated units and the 2% general partner interest (please read Note 3)			—			—			(36,388	)
	Net financing cash flows		(10,492	)		66,231			(13,752	)
	Net cash flows from pro forma and forecasted operating, investing and financing activities	$	12,506		$	9,894		$	23,653

      Please read the accompanying summary of significant accounting policies and forecast assumptions.

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REGENCY ENERGY PARTNERS LP SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND FORECAST ASSUMPTIONS

Note 1.  Basis of Presentation

      The accompanying financial forecast and related notes of Regency Energy Partners LP, the successor to Regency Gas Services LLC, present the forecasted financial results of operations and cash flows of Regency Energy Partners LP for the twelve months ending December 31, 2006 based on the assumptions that, as of the closing of the offering contemplated by this prospectus, Regency Gas Services LLC will be converted to a limited partnership prior to the consummation of this offering and that it and all of its subsidiaries will be contributed to its successor, Regency Energy Partners LP.

      This financial forecast was prepared in connection with the proposed initial public offering of common units in Regency Energy Partners LP, which was formed in September 2005 and which will own Regency Gas Services LLC and its subsidiaries, as we describe elsewhere in this prospectus.

      In constructing the pro forma comparative period for the year ended December 31, 2004, we have added the historical results for the eleven months ended November 30, 2004 for our predecessor to our historical results for the month ended December 31, 2004, the total of which was adjusted as described in “— Pro Forma Financial Information and Financial Forecast.” In constructing the pro forma comparative period for the twelve months ended September 30, 2005, we have added the historical results from the two months ended November 30, 2004 for our predecessor to our historical results for the ten months ended September 30, 2005, the total of which was adjusted as described in “— Pro Forma Financial Information and Financial Forecast.”

      In the presentation of pro forma segment revenues and cost of sales, intersegment eliminations were not considered as they do not impact segment margin. Intersegment revenues and cost of sales would have reduced total revenue and cost of sales by $42.7 million for the twelve-month period ended September 30, 2005 with no impact on total segment margin. Intersegment revenues and cost of sales would have reduced total revenue and cost of sales by $18.5 million for the twelve-month period ended December 31, 2004 with no impact on total segment margin. We are not forecasting any intersegment revenues or cost of sales as the completion of the Regency Intrastate Enhancement Project will eliminate the need for any intersegment sales.

Note 2.  Summary of Significant Accounting Policies

      Organization and Business Operations. Regency Gas Services LLC was formed on April 2, 2003 and began operations on June 2, 2003. We gather, process, market and transport natural gas and NGLs.

      Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

      Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts. Any gain or loss on disposition is included in operating income. The raw natural gas in our pipelines that is used to maintain pipeline minimum pressures is capitalized and classified as property, plant, and equipment. Furthermore, interim financing costs (capitalized interest) associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

      We assess long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.

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      Depreciation. Depreciation of plant and equipment is recorded on a straight-line basis over the following estimated useful lives.

Functional Class of Property	Useful Lives
Gathering and Transmission		5 - 20  years
Gas Plants and Buildings		15 - 35  years
General — Land Rights of Way, Computer Related, Office Related, Telecommunications Related and Vehicles		3 - 10  years

      Intangible Assets. Following the HMTF Investors’ purchase of Regency Gas Services LLC, which we refer to as the HMTF transaction, management identified two classes of separately identifiable intangible assets, which will be amortized on a straight line basis over their useful lives. The two classes of intangible assets are (1) permits and licenses and (2) customer contracts.

      The value of the licenses and permits was determined by discounting the income associated with activities that would be lost over the period required to replace those permits. An intangible asset in the amount of $12.0 million was recognized. The estimated useful life of the asset is 15 years.

      Immediately prior to the HMTF transaction, we renegotiated a number of significant customer contracts. The value of customer contracts was determined by using a discounted cash flow model associated with the contracts. An intangible asset in the amount of $6.5 million was recognized. The estimated useful life for 67% of the contracts is 12 years, while the remaining 33% have an estimated useful life of three years.

      Goodwill. Following the HMTF transaction, goodwill in the amount of $58.5 million was recorded. In accordance with SFAS No. 142 “Goodwill and Other Intangible Assets,” goodwill is not subject to amortization. We test for impairment to determine whether any of the asset value recorded in goodwill should be written off annually on December 31 or more frequently if events or changes in circumstances indicate that an asset might be impaired.

      Other Assets, Net. Other assets, net consist of debt issuance costs, which are capitalized and amortized to expense over the life of the related debt. In addition, we have included $6.1 million of restricted cash in Other Assets, net. This restricted cash relates to borrowings under our credit facility that were restricted for use in funding certain enhancement projects as of September 30, 2005. The funds were spent on these projects in October 2005.

      Gas Imbalance Accounting. Pursuant to imbalance agreements, for which settlement prices are not contractually established, quantities of natural gas over-delivered or under-delivered are recorded monthly as receivables or payables using the lower of cost or market for assets, and market prices for liabilities.

      Revenue Recognition. We earn revenues from domestic sales of natural gas and NGLs and by providing gathering and transmission services. These sales arise from either gas gathering and processing or pipeline transmission services. Revenues associated with these activities are recognized when natural gas products are delivered or at the time services are performed. Our gas purchase contracts are structured so that we earn margins on the resale of natural gas or NGLs reflecting the value added by gathering, processing, or transporting the products. We record revenue and cost of sales on a gross basis for those transactions when we act as the principal and take title to gas that is purchased for resale. When we act as an agent and our customers pay a fee for providing a service such as gathering or transportation, we record fees in revenues and disclose them separately from sales of products.

      Risk Management Activities. We deliver to fractionators the NGLs that are separated from the raw natural gas we gather and process. Under the terms of the contracts for fractionating services, we receive floating rate prices in exchange for title to the NGLs. Because these sales are settled with physical deliveries, these contracts are treated as normal sales and are not marked to market. This arrangement exposes us to price volatility and creates the need to manage that risk.

      To manage commodity price risk, we have implemented a risk management program under which we seek to match sales prices of commodities (especially natural gas) with purchases under our contracts; manage our portfolio of contracts to reduce commodity price risk; optimize our portfolio by active

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monitoring of basis, swing, and fractionation spread exposure; and hedge a portion of our exposure to commodity prices (especially NGLs). On December 2, 2004, as required by covenants in our credit agreements, we entered into certain NGL swaps and crude oil put option contracts. We do not enter into derivative contracts for trading purposes.

      In addition, our $470 million credit facility exposes us to interest rate risk due to the variable nature of the interest rates stated in this credit agreement. The credit agreement required us to enter into an interest rate swap with the objective of hedging a portion of our exposure to interest rate risk.

      Subsequent to the HMTF transaction through June 30, 2005, we evaluated the application of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, to determine whether the transactions qualified for hedge accounting. During this period, we marked these transactions to market and recorded the unrealized gains and losses in revenue for commodity contracts and interest expense for the interest rate swap. At December 31, 2004, our determination of the net fair value of our risk management activities resulted in an asset of $9.0 million.

      Effective July 1, 2005, we elected hedge accounting for our ethane, propane, and butane swaps, as well as for our interest rate swaps. These contracts are designated as cash flow hedges under SFAS No. 133. Changes in the fair value of contracts for which hedge accounting applies will be recorded in Other Comprehensive Income to the extent the hedges are effective. At September 30, 2005, our determination of the net fair value of our risk management activities resulted in a liability of $26.8 million, of which $19.9 million has been recorded as a charge against revenue and $0.2 million has been recorded as a reduction in interest expense, net.

      We have not elected hedge accounting for our crude oil put options, which are used to reduce downside price exposure for other heavy NGLs. At the time that these crude oil put options were purchased, there was no liquid market for contracts that would exactly match the forecasted transactions hedged by the crude oil puts. These contracts have been and will continue to be marked to market with unrealized and realized gains or losses on these contracts recorded in revenue.

      We continue to enter into NGL swaps, and as of September 30, 2005, we have hedged our exposure to commodity price risk for a portion of our forecasted transactions in ethane, propane, butane and natural gasoline through calendar year 2007. As of September 30, 2005, $18.3 million is expected to be reclassified into earnings from Other Comprehensive Income (loss) in the next twelve months.

      Maintenance Costs. Maintenance costs are expensed as incurred.

      Benefits. Payroll and payroll related expenses are included within operating and general and administrative expenses. We provide a portion of medical, dental, and other healthcare benefits to employees, as well as, commencing on June 1, 2005, a 50% matching contribution for the first 6% of employee contributions to their 401(k) accounts. We have no pension obligations.

      Income Taxes. We do not provide in our accounts for federal or state income taxes as such taxes are a liability of our partners.

      Comprehensive Income. Comprehensive income (loss) is the same as net income (loss) for the periods ending December 31, 2004 and prior.

Note 3.  Significant Forecast Assumptions

     Assumption Sensitivities

      A shortfall in cash available for distribution greater than $5.5 million, or 10.0% of cash available for distribution, would result in our generating less than the minimum amount necessary to pay distributions. Throughput volumes and commodity prices are the two primary factors that will influence the amount of cash available for distribution in 2006 relative to this forecast. For example, if all other factors are held constant, a shortfall of 7.7% in our forecasted inlet volumes in the Gathering and Processing Segment would result in a $5.5 million shortfall in our cash available for distribution. Similarly, if all other factors are held constant, a shortfall of 62.1% in our forecasted incremental throughput volumes associated with

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the Regency Intrastate Enhancement Project but not currently subject to executed Firm Transportation agreements would result in a $5.5 million shortfall in our cash available for distribution.

      Our exposure to commodity prices is mitigated by our risk management strategy. As a result, realized gas prices 28.0% below the assumed pricing levels would be required to cause a reduction in our cash available for distribution of $5.5 million when all other factors are held constant.

      Gathering and Processing Segment Revenue. We forecast revenue for our Gathering and Processing segment for the twelve months ending December 31, 2006 based on the following significant assumptions:

•  We will gather 302 MMcf/d of natural gas for the twelve months ending December 31, 2006 as compared to gathering volumes of 280 MMcf/d and 289 MMcf/d for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. This volumetric assumption represents current operating levels.

•  We have entered into a letter of intent with a major producer to provide fee-based gathering services for newly drilled wells in the mid-continent region. We will gather 17 MMcf/d of natural gas for the twelve months ending December 31, 2006 in connection with the development of a new gathering system to provide these services. These volumes will generate $1.9 million of fee revenue.

•  We will generate revenues of $481.7 million related to gathering and processing services for the twelve months ending December 31, 2006 as compared to $374.3 million and $417.9 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. Higher natural gas and NGL prices represent the primary drivers of this increase in revenue.

•  The average natural gas price for each of the three regions in which we operate will range from $7.00/MMBtu to $9.00/MMBtu. Forecasted natural gas prices for 2006 represent an average 33.8% and 16.4% increase over average historical gas prices for the twelve month periods ending December 31, 2004 and September 30, 2005, respectively. The current NYMEX forward prices are 28.8% above the forecast as of January 6, 2006. Weighted average NGL prices, based upon projected production, will be $37.79/bbl. Forecasted NGL prices for 2006 represent an average 27.6% and 7.3% increase over average historical NGL prices for the twelve–month periods ending December 31, 2004 and September 30, 2005, respectively. The current forward prices of NGLs are 11.1% above the forecast as of January 6, 2006.

      Gathering and Processing Segment Cost of Sales. We forecast cost of sales for our Gathering and Processing segment for the twelve months ending December 31, 2006 based on the following significant assumption:

•  We will incur cost of sales of $406.0 million for the twelve months ending December 31, 2006, as compared to $302.9 million and $359.0 million for the twelve months ending December 31, 2004 and September 30, 2005, respectively. Cost of sales is primarily attributable to the purchase of gas and NGLs, but also includes certain third-party transportation and processing fees. Higher commodity prices represent the primary drivers of this increase in cost of sales.

      Gathering and Processing Segment Margin. We forecast segment margin for our Gathering and Processing segment for the twelve months ending December 31, 2006 based on the following significant assumptions:

•  After deducting the cost of sales, we will receive segment margin of $77.7 million related to gathering and processing services for the twelve months ending December 31, 2006 as compared to $71.4 million and $58.9 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. The $58.9 million of segment margin in the twelve months ended September 30, 2005 included $12.7 million of unrealized losses on risk management activities.

•  Our forecast includes the effect of our commodity hedging program under which approximately 95% of our expected price exposure to NGLs has been hedged.

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•  After giving effect to the NGL hedges, a 10% adverse move in both NGL and natural gas prices would reduce our gathering and processing segment margin by approximately 2%.

      Transportation Segment Revenue. We forecast revenue for our Transportation segment for the twelve months ending December 31, 2006 based on the following significant assumptions:

      We will transport 636 MMcf/d of natural gas for the twelve months ending December 31, 2006, in the following categories:

•  265 MMcf/d transported under contract following the completion of first two phases of the Regency Intrastate Enhancement Project, but prior to the December 2005 completion of the final phase. For the year ended December 31, 2004 and the twelve months ended September 30, 2005, we transported 176 MMcf/d and 218 MMcf/d of natural gas, respectively.

•  227 MMcf/d transported under executed firm transportation contracts using incremental capacity created by the December 2005 completion of the Regency Intrastate Enhancement Project.

•  126 MMcf/d transported under executed interruptible transportation contracts using incremental capacity created by the December 2005 completion of the Regency Intrastate Enhancement Project.

•  18 MMcf/d subject to firm transportation contracts currently under negotiation based on executed letters of intent using incremental capacity created by the December 2005 completion of the Regency Intrastate Enhancement Project.

The transportation contracts currently under negotiation and referenced in the immediately preceding bullet point are firm gas transportation contracts with terms ranging from two to five years. We cannot assure you that we will be able to reach agreement with any such shipper on the terms of an acceptable contract.

•  The average rate for transportation service of volumes of natural gas on the Regency Intrastate Pipeline for the year ending December 31, 2006 will be $0.215 per MMcf/d, including fuel charge.

•  The incremental volumes from our Regency Intrastate Enhancement Project will represent approximately 73% of the incremental capacity generated from the project. Additionally, total forecasted volumes will represent approximately 80% of total forecasted system capacity.

•  The average natural gas price for the transportation segment will average $9.00 per MMBtu for 2006. Forecasted natural gas prices for 2006 represent an average 47.8% and 27.0% increase over average historical gas prices for the twelve-month periods ending December 31, 2004, and September 30, 2005, respectively. The current NYMEX forward prices of natural gas are 8.2% above the forecast as of January 6, 2006.

•  We will, exclusive of the portion of our Regency Intrastate Enhancement Project completed in December 2005, receive revenues of $356.3 million related to services provided under transportation agreements for the twelve months ending December 31, 2006, as compared to $146.1 million and $200.4 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. Higher natural gas and NGL prices represent the primary drivers of this increase in revenue. Our forecast is based on 58% of these volumes being generated from fees for transporting natural gas and 42% of these volumes being generated by our purchases of natural gas that we transport and sell. This reflects the historical breakdown as of October 2005.

•  The 80-mile extension of our Regency Intrastate Enhancement Project completed in December 2005 will generate additional revenues of $29.6 million for the twelve months ending December 31, 2006, all of which will come from fee-based arrangements.

•  We will generate $1.7 million of fee revenue in connection with $8.0 million of growth capital expenditures, exclusive of the Regency Intrastate Enhancement Project, in 2006.

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      Transportation Segment Cost of Sales. We forecast cost of sales for our Transportation segment for the twelve months ending December 31, 2006 based on the following significant assumption:

•  We will incur cost of sales of $335.6 million for the twelve months ending December 31, 2006, as compared to $137.3 million on a pro forma basis for the twelve months ended December 31, 2004 and $188.4 million on a pro forma basis for the twelve months ended September 30, 2005. Cost of sales is primarily attributable to the purchase of gas under our merchant arrangements under which we purchase, transport and sell natural gas. Higher commodity prices represent the primary drivers of this increase in cost of sales.

      Transportation Segment Margin. We forecast segment margin for our Transportation segment for the twelve months ending December 31, 2006 based on the following significant assumptions:

•  We will receive segment margin of $20.1 million related to services provided under transportation agreements on our Regency Intrastate Pipeline, including the two segments built to expand the existing system, for the twelve months ending December 31, 2006, as compared to $8.8 million and $12.1 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively.

•  The 80-mile extension of our Regency Intrastate Pipeline completed in December 2005 will generate additional segment margin of $29.6 million for the twelve months ending December 31, 2006, all of which will come from fee-based transportation arrangements.

•  We will generate $1.7 million of segment margin as a result of our $8.0 million of growth capital expenditures.

•  A 10% adverse move in natural gas prices would reduce our transportation segment margin by approximately 2%.

      Operating Expenses. We forecast operating expenses for the twelve months ending December 31, 2006 based on the following significant assumption:

•  Operating expenses will be $22.2 million for the twelve months ending December 31, 2006, as compared to $20.9 million and $21.4 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. This includes $2.2 million in incremental expenses related to our Regency Intrastate Enhancement Project, $0.2 million in incremental expenses relating to our mid-continent gathering project and assumes $1.6 million of reductions to our existing operating expenses, based on initiatives currently in progress.

      General and Administrative Expenses. We forecast general and administrative expenses for the twelve months ending December 31, 2006 based on the following significant assumptions:

•  Our total general and administrative expenses for 2006, excluding general and administrative expenses associated with being a public company, will be $15.2 million as compared to $9.7 million and $13.0 million on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. This includes $2.2 million of non-cash expense for distributions on the unit distribution rights associated with the 340,000 restricted units we expect to grant under our long term incentive plan upon the consummation of this offering. See Note 10 of the Notes to Consolidated Financial Statements of Regency Gas Services LLC for a more detailed description of the proposed grants under our long term incentive plan.

•  Our incremental general and administrative expenses associated with being a public company, including reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, Sarbanes-Oxley Act compliance, and SEC reporting and filing requirements, will be $2.5 million for the twelve months ending December 31, 2006.

      Depreciation and Amortization Expenses. We forecast depreciation and amortization expenses for the twelve months ending December 31, 2006 to be $29.1 million as compared to $20.3 million and $21.3 million of depreciation and amortization expenses on a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. We forecast

47

depreciation and amortization expense for the twelve months ending December 31, 2006 based on a number of specific assumptions, including:

•  $19.4 million from existing assets (not including capital expenditures or assets related to the Regency Intrastate Enhancement Project) based on a 16-year weighted average useful life.

•  $7.8 million from fixed assets and capital expenditures primarily associated with the Regency Intrastate Enhancement Project, based on a 19-year weighted average useful life.

•  $1.9 million associated with intangibles.

      Working Capital. Our working capital needs are minimal, and to the extent necessary are funded through temporary borrowings under our revolving credit facility. Accordingly, changes in working capital are excluded from net operating cash flows in our presentation of Pro Forma and Forecasted Results of Operations and Cash Flows. Interest expense associated with these temporary borrowings is included in the forecast.

      Capital Expenditures. We forecast capital expenditures for the twelve months ending December 31, 2006 based on the following significant assumptions:

•  Our maintenance capital expenditures will be $6.0 million for the twelve months ending December 31, 2006 as compared to $5.9 million and $6.4 million for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. These expenditures will include $2.7 million in well connect costs and $3.3 million in various other expenditures, such as compressor overhauls. These expenditures do not include any maintenance capital expenditures in 2006 related to the Regency Intrastate Enhancement Project, as we do not expect to incur maintenance capital expenditures related to this project in 2006.

•  Our growth capital expenditures will be $22.6 million for the twelve months ending December 31, 2006 as compared to $11.3 million and $87.9 million for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. The $87.9 million consisted primarily of expenditures related to the Regency Intrastate Enhancement Project. The forecasted growth capital expenditures relate to several projects, including $8.7 million related to the Regency Intrastate Enhancement Project. Other 2006 growth capital projects will include a 200 MMcf/d dew point control facility in our north Louisiana region, a gathering system development project in our mid-continent region, and an acid gas injection well at our Waha gas processing plant, and will be financed under our existing credit facility.

•  Consistent with our acquisition strategy, we intend to pursue strategic acquisitions that we expect to be accretive to our distributable cash flow; however, because of the uncertain nature of the acquisition environment, we have not included an estimate of future acquisition capital expenditure requirements. If we are successful in completing acquisitions, we anticipate that our primary source of financing for these acquisitions will be commercial bank borrowings and the issuance of debt and equity securities.

      Financing. We forecast financing for the twelve months ending December 31, 2006 based on the following significant financing assumptions:

•  Our average debt level will be $378 million, comprised of a $308 million first lien facility with an interest rate of London Interbank Offered Rate, or LIBOR, plus 2.25%, and $70 million outstanding on our $160 million revolving credit facility, which has an interest rate of LIBOR plus 2.25% on borrowed funds and a commitment fee of 0.5% on unborrowed funds.

•  For calculating our floating interest rate exposure, we have assumed a 2006 LIBOR of 4.75% based on forward curves for 2006 as of January 6, 2006. This exposure is offset by our existing interest rate hedges which include $200 million of fixed-for-floating swaps at a weighted average rate of 3.95%.

•  Our debt balance as of September 30, 2005 was $308.4 million. During the period between September 30, 2005 and December 31, 2005, we incurred additional debt of $50.0 million primarily

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	to complete the Regency Intrastate Enhancement Project. Our debt balance as of December 31, 2005 was $358.4 million.
•	Based on these assumptions, our average interest rate will be 7.3%, and our interest expense will be $25.3 million for the twelve months ending December 31, 2006 as compared to $9.2 million and $12.1 million on a pro forma basis for the year ended December 31, 2004 and for the twelve months ended September 30, 2005, respectively.
•	We will finance our expected growth capital expenditures using our revolving credit facility.

      Payments of Distributions on Common Units, Subordinated Units and the 2% General Partner Interests During 2006. We forecast that distributions on common units, subordinated units and on the 2% general partner interests for the twelve months ending December 31, 2006 will be approximately $36.4 million in the aggregate, which includes distributions for the period February 3 through March 31, 2006 and the next two calendar quarters of 2006. We do not include the fourth quarter 2006 distribution because the quarterly distribution is actually paid during the first quarter of 2007, although we will pay quarterly distributions within 45 days after the close of the quarter. The distribution on common units, subordinated units and the 2% general partner interest related to the 2006 results, including the fourth quarter 2006 distribution, will be approximately $50.1 million for the twelve months ended December 31, 2006, assuming this offering closes on February 3, 2006. Please see “— Forecasted Cash Available for Distribution for The Twelve Months Ending December 31, 2006.”

      Regulatory, Industry and Economic Factors. We forecast for the twelve months ending December 31, 2006 based on the following significant assumptions related to regulatory, industry and economic factors:

•  No material nonperformance or credit-related defaults by suppliers, customers or vendors will occur. There will not be any new federal, state or local regulation of the portions of the energy industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business.

•  No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated and material events will occur.

•  There will not be any major adverse change in the midstream sector of the energy industry or in general economic conditions.

•  Market, regulatory, insurance and overall economic conditions will not change substantially.

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FORECASTED CASH AVAILABLE FOR DISTRIBUTION

FOR THE TWELVE MONTHS ENDING DECEMBER 31, 2006

      The table below entitled “Forecasted Cash Available for Distribution for the Twelve Months Ending December 31, 2006” sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner based on the Statement of Forecasted Results of Operations and Cash Flows set forth above. Based on the financial forecast, we forecast that our EBITDA will be approximately $89.2 million for the twelve months ending December 31, 2006, which amount would be sufficient to fully fund distributions to our unitholders and general partner at the initial distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis).

      EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP.

      You should read “Note 3. Significant Forecast Assumptions” included as part of the financial forecast for a discussion of the material assumptions underlying our forecast of EBITDA that is included in the table below. Our forecast is based on those material assumptions and reflects our judgment of conditions we expect to exist and the course of action we expect to take. The assumptions disclosed in our financial forecast are those that we believe are significant to our ability to generate the forecasted EBITDA. If our estimate is not achieved, we may not be able to pay distributions on the common units at the initial distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis). Our financial forecast and the forecast of cash available for distribution set forth below have been prepared by our management. Our independent auditors have not examined, compiled, or otherwise applied procedures to our financial forecast and the forecast of cash available for distribution set forth below and, accordingly, do not express an opinion or any other form of assurance on it.

      When considering our forecast of cash available for distribution for the twelve months ending December 31, 2006, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in financial forecast and the forecast of cash available for distribution set forth below.

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REGENCY ENERGY PARTNERS LP

FORECAST OF CASH AVAILABLE FOR DISTRIBUTION

FOR THE TWELVE MONTHS ENDING DECEMBER 31, 2006

			Twelve Months Ending
			December 31, 2006(a)
			($ in thousands,
			except per unit data)
Net Forecasted Operating Cash Flows			$	66,041
Plus:
	Interest expense, net			25,328
Less:
	Non-cash LTIP expense			(2,192	)
		EBITDA		89,177
Less:
	Interest expense, net			(25,328	)
	Maintenance capital expenditures			(6,000	)
	Growth capital expenditures			(22,636	)
Plus:
	Non-cash LTIP expense			2,192
	Borrowings for growth capital expenditures			22,636
Cash Available for Distribution			$	60,041
Forecasted Cash Distributions:
	Forecasted distribution per unit		$	1.40
	Forecasted distributions to our public common unitholders(b)			19,250
	Forecasted distributions to common units held by the HMTF Investors(b)			7,495
	Forecasted distributions to subordinated units held by the HMTF Investors			26,745
	Forecasted distributions to general partners interest held by the HMTF Investors			1,092
		Total forecasted distributions to our unitholders and general partner(c)	$	54,583

(a)	The forecast in this table is based on the assumptions set forth in “— Regency Energy Partners LP Summary of Significant Accounting Policies and Forecast Assumptions.”
(b)	Assumes the underwriters’ option to purchase additional common units has not been exercised. If that option is exercised, we will use the net proceeds from the sale of the units subject to the option to redeem an equal number of common units from the HMTF Investors. As a result, the exercise of the option will not increase the aggregate amount of the required distributions to the holders of common units since the total number of common units outstanding will not change.
(c)	Represents the amount required to fund distributions to our unitholders for four quarters based upon our initial distribution rate of $1.40 per unit. Excludes $0.48 million of distributions on the unit distribution rights associated with the 340,000 restricted units that we expect to grant under our long term incentive plan upon the consummation of this offering.

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Pro Forma Available Cash for Year Ended December 31, 2004 and Twelve Months Ended September 30, 2005

      If we had completed the transactions contemplated in this prospectus on January 1, 2004 as a publicly traded partnership, pro forma cash available for distribution generated during the year ended December 31, 2004 would have been approximately $33.8 million. This amount would have been sufficient to make aggregate cash distributions on all our common units at the initial distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) and 22.1% of the distribution attributable to the subordinated units. If we had completed the transactions contemplated in this prospectus on September 30, 2004, our pro forma cash available for distribution for the twelve months ended September 30, 2005 would have been approximately $30.9 million. This amount would have been sufficient to make aggregate cash distributions on all our common units at the initial distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) and 11.6% of the distributions attributable to the subordinated units.

      The following table illustrates, on a pro forma basis, for the year ended December 31, 2004 and for the twelve months ended September 30, 2005, the amount of cash available for distribution that would have been available for distributions to our unitholders, assuming in each case that the offering had been consummated at the beginning of such period. We have reconciled our pro forma cash available for distributions to net cash provided (used) by operating activities. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

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REGENCY ENERGY PARTNERS LP

UNAUDITED PRO FORMA CONSOLIDATED AVAILABLE CASH

			Twelve Months			Twelve Months
			Ended			Ended
			December 31,			September 30,
			2004 (a)			2005 (b)
			($ in thousands,
			except per unit data)
Net cash provided by operating activities			$	27,471		$	19,324
	Interest expense, net(c)			6,432			14,977
	Non-cash charges included in EBITDA(d)			(3,164	)		(22,352	)
	Net changes in working capital accounts and other assets(e)(p)			8,915			10,719
EBITDA				39,654			22,668
Pro forma adjustments
	Waha asset purchase pro forma(f)			2,072			—
	Expenses related to acquisition by the HMTF Investors pro forma(g)			10,025			8,619
	Adjustments for offering transactions(h)			(2,124	)		(1,524	)
	Discontinued operations(i)			121			(625	)
Pro forma EBITDA				49,748			29,138
Less:
	Additional expense of being a publicly traded company(j)			2,500			2,500
	Interest expense, net(k)			9,609			12,629
	Maintenance capital expenditures(l)			5,906			6,410
	Growth capital expenditures(m)			11,329			87,926
	Principal repayments on debt(n)			10,492			6,199
	Net changes in working capital accounts and other assets(e)			8,915			10,719
	Unrealized gains on risk management activities(o)			322			322
Plus:
	Borrowings for growth capital expenditures(p)(q)			11,329			72,926
	Borrowing for principal repayments on debt(p)(q)			10,492			6,199
	Borrowings to replenish working capital and other assets(e)(p)(q)			8,915			10,719
	Equity contribution for growth capital expenditures(r)			—			15,000
	Unrealized losses on risk management activities(o)			—			13,556
	Non-cash LTIP expense(s)			2,391			2,391
	Loss on debt refinancing(t)			—			7,724
Pro forma cash available for distribution			$	33,802		$	30,948
	Pro forma distribution associated with non-vested restricted units(u)			476			476
Pro forma cash distributions:
	Distribution to public common unitholders			19,250			19,250
	Distribution to HMTF Investors — common units			7,495			7,495
	Distribution to HMTF Investors — subordinated units			5,905			3,108
	Distribution to HMTF Investors — general partner interest			676			619
		Total distributions to unitholders	$	33,326		$	30,472
Annualized initial quarterly distribution per unit(v)			$	1.40		$	1.40
Aggregate distribution payable at annualized initial quarterly distribution(v)			$	54,583		$	54,583
Excess (shortfall)				(21,257	)		(24,111	)
Percent of distributions payable to common unitholders				100.0	%		100.0	%
Percent of distributions payable to subordinated unitholders				22.1	%		11.6	%

(a) Historical reconciled to pro forma as if the March 1, 2004 acquisition of our west Texas assets had occurred on January 1, 2004; the December 1, 2004 acquisition of Regency Gas Services LLC by the HMTF Investors had occurred on January 1, 2004; and the pro forma adjustment had been included. Please read “Consolidated Statements of Operations — Regency Gas Services LLC,”

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	“Consolidated Statements of Cash Flows — Regency Gas Services LLC, Summary Historical and Pro Forma Financial and Operating Data,” “Unaudited Pro Forma Condensed Financial Statements — Regency Energy Partners LP Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2004” and “Unaudited Pro Forma Condensed Financial Statements — Regency Energy Partners LP Unaudited Pro Forma Condensed Combined Statement of Operations for the Nine Months Ended September 30, 2005.”
(b)	Historical reconciled to pro forma to include a pro forma adjustment for this offering and the acquisition of Regency Gas Services LLC by the HMTF Investors. Please read “Consolidated Statements of Operations — Regency Gas Services LLC,” “Consolidated Statements of Cash Flows — Regency Gas Services LLC, Summary Historical and Pro Forma Financial and Operating Data,” “Unaudited Pro Forma Condensed Financial Statements — Regency Energy Partners LP Unaudited Pro Form Condensed Combined Statement of Operations for the Year Ended December 31, 2004” and “Unaudited Pro Forma Condensed Financial Statements — Regency Energy Partners LP Unaudited Pro Forma Condensed Combine Statement of Operations for the Nine Months ended September 30, 2005.”
(c)	Amount represents historical interest expense, net incurred to fund growth capital expenditures, principal repayments on term debt and decreases in working capital accounts. This item is a necessary reconciling item between net cash provided by operations and EBITDA.
(d)	Primarily includes non-cash charges that are included in EBITDA but not included in net cash provided by operating activities, such as loss on debt refinancing and risk management portfolio value changes. These historical non-cash adjustments are necessary to reconcile Net Cash Provided by Operating Activities to EBITDA.
	Non-Cash Charges included in Pro Forma EBITDA

	For the Twelve Months Ended
	December 31, 2004			September 30, 2005
	($ in thousands)
Amortization of debt issuance costs	$	(464	)	$	(1,032	)
Loss on debt refinancing		(3,022	)		(9,340	)
Risk management portfolio value changes		322			(13,234	)
Gain on sale of assets		—			1,254
	$	(3,164	)	$	(22,352	)

(e)	Represents actual net changes in working capital accounts and other assets incurred for the periods indicated.
(f)	The twelve months ended December 31, 2004 includes the January and February 2004 pro forma adjustments for the Waha asset purchase excluding depreciation and interest expense, which are not components of EBITDA. These pro forma components are listed in the table below.

	Amount
	($ in millions)
Total Revenue	$	21.7
Total Cost of Sales		17.9
Operating expenses		1.3
General and administrative		0.4
Pro forma adjustment	$	2.1

(g) Represents the expenses of the predecessor relating directly to the sale of Regency Gas Services LLC to the HMTF Investors. These expenses would have been recognized in 2003 prior to the sale if the HMTF Investors had acquired us on January 1, 2004. These non-recurring expenses are comprised of the loss on debt refinancing and transaction expenses. The transaction expenses consisted of compensation, legal and other expenses directly related to the sale and were paid by the seller prior to the HMTF acquisition.

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(h)	Represents the inclusion of pro forma adjustments for (i) compensation expenses related to distributions or unit distributions rights associated with the 340,000 restricted units that we expect to grant under our long term incentive plan upon the consummation of this offering and (ii) the elimination of the management fees payable to Hicks Muse that will be terminated upon the closing of the offering in accordance with an agreement between Regency Gas Services LLC and an affiliate of Hicks, Muse. Please read “Use of Proceeds.”
(i)	Represents discontinued operations, which is a necessary reconciling item between historical EBITDA and pro forma EBITDA due to the fact that our Pro Forma Statements of Operations only report to Income (Loss) from Continuing Operations.
(j)	Includes incremental general and administrative expenses we will incur as a result of being a publicly traded limited partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect these incremental general and administrative expenses to total approximately $2.5 million per year.
(k)	Amount represents pro forma interest expense, net incurred to fund growth capital expenditures, principal repayments on term debt and decreases in working capital accounts. This amount is deducted from Pro forma EBITDA since it decreases pro forma cash available for distributions.
(l)	Represents actual maintenance capital expenditures incurred for the periods indicated.
(m)	Represents actual growth capital expenditures for the periods indicated, excluding the growth capital expenditures associated with the acquisition of our west Texas assets. The west Texas assets have been included in our pro forma results as if they were acquired on January 1, 2004 as described in note (a) above.
(n)	Represents actual principal repayments on debt for the periods indicated.
(o)	Unrealized gains and losses from risk management activities are excluded from pro forma cash available for distribution because these gains and losses have not yet been realized, and to the extent they become realized in the future, the performance of the hedged item will neutralize the realized gain or loss resulting in no impact on current or future cash available for distributions.
(p)	At the closing of this offering, we will have a credit facility that will provide for an aggregate of $160.0 million available borrowing capacity of which we expect approximately $100.0 million will be available for borrowing. We intend to use our credit facility to satisfy our working capital needs, fund principal payments on our long-term debt and finance growth capital expenditures. We expect to fund growth capital expenditures from borrowings and equity contributions.
(q)	For purposes of determining pro forma cash available for distribution, we have assumed that we are operating as a publicly traded partnership, including borrowing the amounts necessary to cover growth capital expenditures, principal repayments on debt replenishment of working capital and other assets, as reflected in the table. Our historical borrowings were used to fund the acquisition of the Waha assets and to facilitate the HMTF transaction, neither of which borrowings would have increased our cash available for distribution and on a pro forma basis would have occurred prior to the periods presented. The pro forma borrowings shown for Net proceeds from borrowings under the credit facility in the Pro Forma and Forecasted Results of Operation and Cash Flows on page 41 do not assume we are operating as a publicly traded partnership, and therefore, the borrowings reflect only those that actually occurred.
(r)	Equity investment by the HMTF Investors to finance, in part, the Regency Intrastate Enhancement Project, which is assumed to have occurred on January 1, 2005.
(s)	Represents non-cash compensation expenses related to distributions on the unit distribution rights associated with the 340,000 restricted units that we expect to grant under our long term incentive plan upon the consummation of this offering.
(t)	Loss on debt refinancing represents actual non-cash charges associated with the write-off of debt issuance costs from debt refinancings, which do not affect our current or future ability to make cash distributions.
(u)	Reflects payments for distribution equivalent rights granted in connection with grants of 340,000 restricted units under our long term incentive plan at the consummation of this offering.

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(v) The table below sets forth the assumed number of outstanding common units and subordinated units upon the closing of this offering (assuming the underwriters’ option to purchase additional common units has not been exercised) and the aggregate distribution amounts payable on our common units, subordinated units and general partner interest for four quarters at our initial distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis).

		Number		Distributions for
		of Units		Four Quarters
				($ in thousands)
Pro forma distributions on publicly held common units			13,750,000	$	19,250
Pro forma distributions on common units held by HMTF Investors			5,353,896		7,495
Pro forma distributions on subordinated units held by HMTF Investors			19,103,896		26,745
Pro forma distributions on 2% general partner interest			779,751		1,092
	Total distributions on units		38,987,543	$	54,583

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HOW WE MAKE CASH DISTRIBUTIONS

Operating Surplus and Capital Surplus

Overview

      All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Characterization of Cash Distributions

      We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Definition of Available Cash

      We define available cash in the glossary, and it generally means, for each fiscal quarter all cash on hand at the end of the quarter:

•  less the amount of cash reserves established by our general partner:

•  to provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);

•  to comply with applicable law, any of our debt instruments or other agreements; and

•  to provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;

•  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Definition of Operating Surplus

      We define operating surplus in the glossary, and for any period it generally means:

•  our cash balance on the closing date of this offering; plus

•  $20.0 million (as described below); plus

•  all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

•  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

•  operating expenses; less

•  the amount of cash reserves established by our general partner for future operating expenditures.

      If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

      Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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      As described above, operating surplus does not reflect actual cash on hand at closing that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $20.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus.

Definition of Capital Surplus

      We also define capital surplus in the glossary, and it will generally be generated only by:

•  borrowings other than working capital borrowings;

•  sales of debt and equity securities; and

•  sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or non-current assets sold as part of normal retirements or replacements of assets.

Subordination Period

Overview

      During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.35 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Definition of Subordination Period

      We define the subordination period in the glossary. Except as described below under “— Early Termination of Subordination Period,” the subordination period will extend until the first day of any quarter beginning after December 31, 2008 that each of the following tests are met:

•  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

•  there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

      The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:

•  distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $2.10 (150% of the annualized minimum quarterly distribution) for any four-quarter period ending on or after December 31, 2006;

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•  the “adjusted operating surplus” (as defined below) generated during any four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.10 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units on a fully diluted basis; and

•  there are no arrearages in payment of the minimum quarterly distribution on the common units.

Definition of Adjusted Operating Surplus

      We define adjusted operating surplus in the glossary, and for any period it generally means:

•  operating surplus generated with respect to that period; less

•  any net increase in working capital borrowings with respect to that period; less

•  any net reduction in cash reserves for operating expenditures made with respect to that period not relating to an operating expenditure made with respect to that period; plus

•  any net decrease in working capital borrowings with respect to that period; plus

•  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

      Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Effect of Expiration of the Subordination Period

      Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

•  the subordination period will end and each subordinated unit will immediately convert into one common unit;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

      We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•  First, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•  second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•  third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•  thereafter, in the manner described in “— Incentive Distribution Rights” below.

      The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

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Distributions of Available Cash from Operating Surplus After the Subordination Period

      We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•  First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•  thereafter, in the manner described in “— Incentive Distribution Rights” below.

      The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Incentive Distribution Rights

      Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

      If for any quarter:

•  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

•  first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);

•  second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”);

•  third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.5250 per unit for that quarter (the “third target distribution”); and

•  thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

      In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash from Operating Surplus

      The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed additional capital to maintain its 2% general

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partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

			Marginal
			Percentage Interest
			in Distributions
	Total Quarterly Distribution				General
	Target Amount		Unitholders		Partner
Minimum Quarterly Distribution		$0.3500		98%		2%
First Target Distribution		up to $0.4025		98%		2%
Second Target Distribution		above $0.4025 up to $0.4375		85%		15%
Third Target Distribution		above $0.4375 up to $0.5250		75%		25%
Thereafter		above $0.5250		50%		50%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

      We will make distributions of available cash from capital surplus, if any, in the following manner:

•  first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

•  second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•  thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

      The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

     Effect of a Distribution from Capital Surplus

      The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

      Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to our general partner. The percentage interests shown for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

      In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•  the minimum quarterly distribution;

•  the target distribution levels;

•  the unrecovered initial unit price; and

•  the number of common units into which a subordinated unit is convertible.

      For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

      In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

     Overview

      If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

      The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. There may not, however, be sufficient gain upon our liquidation to enable the holders of common units to recover fully all of these amounts, even though there may be cash available to pay distributions to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

     Manner of Adjustments for Gain

      The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•  First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

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•  second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:

(1) the unrecovered initial unit price for that common unit;

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

(3) any unpaid arrearages in payment of the minimum quarterly distribution;

•  third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:

(1) the unrecovered initial unit price for that subordinated unit; and

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•  fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

•  fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

•  sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

•  thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

      The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

     Manner of Adjustments for Losses

      If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•  first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

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•  second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

•  thereafter, 100% to our general partner.

      The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

     Adjustments to Capital Accounts

      We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. If we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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SELECTED HISTORICAL AND SELECTED PRO FORMA FINANCIAL AND OPERATING DATA

      The following table shows selected historical financial and operating data of our predecessors, Regency LLC Predecessor and Regency Gas Services LLC, and unaudited pro forma financial data of Regency Energy Partners LP for the periods and as of the dates indicated. Our historical results of operations for the periods presented below may not be comparable, either from period to period or going forward, for the following reasons:

•  Regency Gas Services LLC was formed on April 2, 2003 and commenced operations on June 2, 2003 with the acquisition of certain natural gas gathering, processing and transportation assets from subsidiaries of El Paso. As a result, we do not have any financial results for periods prior to April 2, 2003 and our results of operations for the period ended December 31, 2003 includes only seven months of financial results.

•  On March 1, 2004, Regency Gas Services LLC acquired certain natural gas gathering and processing assets from Duke Energy Field Services, LP. As a result, our historical financial results for the periods prior to March 1, 2004 do not include the financial results from the operation of these assets.

•  In connection with the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004, the purchase price was “pushed-down” to the financial statements of Regency Gas Services LLC. As a result of this “push-down” accounting, the book basis of our assets was increased to reflect the purchase price, which had the effect of increasing our depreciation expense. Also, the increased amount of debt we incurred in connection with the acquisition increased our interest expense subsequent to December 1, 2004.

•  After our acquisition by the HMTF Investors, we initiated a risk management program comprised of commodity swaps and crude oil puts that we accounted for using mark-to-market accounting. These amounts are included in unrealized/ realized gain (loss) from risk management activities.

•  In response to transmission capacity constraints in north Louisiana, we significantly expanded and extended our pipeline assets in this region, increasing our capacity to 800 MMcf/d from 200 MMcf/d and increasing the length of the pipeline to 280 miles from 200 miles. The total cost of the project, which was completed in December 2005, is expected to be approximately $140 million.

      We refer to Regency Gas Services LLC as “Regency LLC Predecessor” for periods prior to the acquisition by the HMTF Investors.

      The selected historical financial data for the period from acquisition date (December 1, 2004) to December 31, 2004 are derived from the audited financial statements of Regency Gas Services LLC. The selected historical financial data for the period from January 1, 2004 to November 30, 2004 and the period from inception (April 2, 2003) to December 31, 2003 are derived from the audited financial statements of Regency LLC Predecessor. The selected historical financial data for the nine months ended September 30, 2004 were derived from the unaudited financial statements of Regency LLC Predecessor, and the selected historical financial data for the nine months ended September 30, 2005 were derived from the unaudited financial statements of Regency Gas Services LLC.

      The selected pro forma financial data for the nine months ended September 30, 2005 and for the year ended December 31, 2004 are derived from the unaudited pro forma financial statements of Regency Energy Partners LP. The pro forma adjustments have been prepared as if this offering and the related transactions had taken place on September 30, 2005, in the case of the pro forma balance sheet or as of January 1, 2004, in the case of the pro forma statements of operations for the year ended December 31, 2004 and the nine months ended September 30, 2005. The pro forma statement of operations for the year ended December 31, 2004 has also been adjusted to give effect to the impact on our reported results of the acquisition of Regency Gas Services LLC by the HMTF Investors and our purchase of assets from Duke Energy Field Services as if such transactions occurred on January 1, 2004.

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      The following table includes the non-GAAP financial measures of EBITDA and total segment margin. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. We define total segment margin as total revenue, including service fees, less cost of gas and liquids and other cost of sales. For discussion of the non-GAAP financial measures of EBITDA and total segment margin, and for a reconciliation of EBITDA and total segment margin to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary — Non-GAAP Financial Measures.”

													Regency Gas Services LLC
				Regency LLC Predecessor
													Period from						Regency Energy Partners LP
													Acquisition						Unaudited Pro Forma
				Period from			Period from			Nine Months			Date			Nine Months
				Inception			January 1,			Ended			(December 1,			Ended						Nine Months
				(April 2, 2003) to			2004 to			September 30,			2004) to			September 30,			Year Ended			Ended
				December 31,			November 30,			2004			December 31,			2005			December 31,			September 30,
				2003			2004			(unaudited)			2004			(unaudited)			2004			2005
				($ in thousands except per unit data)
Statement of Operations Data:
Total revenue(1)				$	186,533		$	432,321		$	339,106		$	47,841		$	434,566		$	501,895		$	434,566
Total expense
	Total cost of sales				163,461			362,762			285,951			40,986			386,892			421,658			386,892
	Operating expenses				7,012			17,786			13,651			1,819			15,495			20,947			15,495
	General and administrative				2,651			6,571			5,323			638			9,571			9,742			10,614
	Transaction expenses				724			7,003			—			—			—			—			—
	Depreciation and amortization				4,324			10,129			8,146			1,613			15,718			20,314			15,718
			Total operating expenses		178,172			404,251			313,071			45,056			427,676			472,661			428,719
Operating income					8,361			28,070			26,035			2,785			6,890			29,234			5,847
Other income and deductions
	Interest expense, net				(2,392	)		(5,097	)		(4,139	)		(1,335	)		(12,684	)		(9,193	)		(10,528	)
	Loss on debt refinancing				—			(3,022	)		(1,406	)		—			(7,724	)		—			(7,724	)
	Other income and deductions, net				205			186			67			14			226			200			226
			Total other income and deductions		(2,187	)		(7,933	)		(5,478	)		(1,321	)		(20,182	)		(8,993	)		(18,026	)
Net income (loss) from continuing operations					6,174			20,137			20,557			1,464			(13,292	)		20,241			(12,179	)
Discontinued operations					—			(121	)		(14	)		—			732			—			—
Net income (loss)				$	6,174		$	20,016		$	20,543		$	1,464		$	(12,560	)	$	20,241		$	(12,179	)
General partner interest in pro forma net income (loss)																			$	405		$	(244	)
Limited partner interest in pro forma net income (loss)																			$	19,836		$	(11,935	)
Pro forma net income per limited partner unit																			$	0.52		$	(0.31	)
Balance Sheet Data (at period end):
Property, plant and equipment, net				$	118,986								$	328,348		$	404,446					$	404,446
Total assets					164,330									486,489			598,511						598,511
Long-term debt					66,600									250,000			308,350						308,350
Net equity					59,856									176,964			157,180						157,180
Cash Flow Data:
Net cash flows provided by (used in):
	Operating activities			$	6,494		$	32,401		$	29,501		$	(4,930	)	$	21,354
	Investing activities				(123,165	)		(84,721	)		(81,151	)		(129,947	)		(81,326	)
	Financing activities				118,245			56,380			53,880			132,515			70,780
Other Financial Data:
Total segment margin(1)				$	23,072		$	69,559		$	53,155		$	6,855		$	47,674		$	80,237		$	47,674
EBITDA(1)					12,890			35,242			32,828			4,412			15,842			49,748			14,067
Maintenance capital expenditures					1,633			5,548			4,226			358			4,730			5,906			4,730
Segment Financial and Operating Data:
	Gathering and Processing Segment:
		Financial data:
			Segment margin(1)	$	18,805		$	61,347		$	46,282		$	6,247		$	37,571		$	71,417		$	37,571
			Operating expenses		6,131			16,230			12,444			1,655			14,231			19,227			14,231
		Operating data:
			Natural gas throughput (MMcf/d)		199			279			272			289			284			299			284
			NGL gross production (Bbls/d)		9,434			14,487			13,841			15,675			14,824			15,726			14,824
	Transportation Segment:
		Financial data:
			Segment margin	$	4,268		$	8,212		$	6,873		$	608		$	10,103		$	8,820		$	10,103
			Operating expenses		881			1,556			1,207			164			1,264			1,720			1,264
		Operating data:
			Throughput (MMcf/d)		197			179			177			150			232			176			232

(1)  Includes $0.3 million of unrealized gains on risk management activities for the one month ended December 31, 2004 and $12.7 million of net unrealized losses on risk management activities for the nine months ended September 30, 2005.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

      The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes and our pro forma financial statements included elsewhere in this prospectus.

Overview

      We are a Delaware limited partnership formed to capitalize on opportunities in the midstream sector of the natural gas industry. We own and operate five major natural gas gathering systems and four active processing plants in north Louisiana, west Texas and the mid-continent region of the United States, which includes Kansas, Oklahoma, Colorado, and the Texas Panhandle. We are engaged in gathering, processing, marketing and transporting natural gas and natural gas liquids, or NGLs. We connect natural gas wells of producers to our gathering systems through which we transport the natural gas to processing plants operated by us or by third parties. The processing plants separate NGLs from the natural gas. We then sell and deliver the natural gas and NGLs to a variety of markets.

Our Operations

      We manage our business and analyze and report our results of operations through two business segments:

•  Gathering and Processing: provides “wellhead to market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate the NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

•  Transportation: delivers natural gas from northwest Louisiana to north central Louisiana through our 280-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project.

     Gathering and Processing Segment

      Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, our current contract portfolio and natural gas and NGL prices.

      We measure the performance of this segment primarily by the segment margin it generates, which we define as total revenues, including service fees, less the cost of natural gas and liquids and other cost of sales. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs. We regard the segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements.

      Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

•  Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in

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	higher commodity price environments. For the nine months ended September 30, 2005, these arrangements accounted for about 24% of our natural gas volumes for this segment.
•	Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins cannot be negative. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component). For the nine months ended September 30, 2005, these arrangements accounted for about 50% of our natural gas volumes for this segment.
•	Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) conditioning floors that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating, and compression. For the nine months ended September 30, 2005, these arrangements accounted for approximately 26% of our natural gas volumes for this segment.

      An important aspect of our contract portfolio management strategy is to decrease our keep-whole contract risk exposure. Immediately following the acquisition of our mid-continent assets, we terminated our month-to-month keep-whole arrangements and replaced them with fee-based or percentage-of-proceeds agreements or variations thereof. In addition, we seek to replace our longer term keep-whole arrangements as they expire or whenever the opportunity presents itself. At the time of the acquisition of our mid-continent assets, approximately 71% of our natural gas volumes associated with those assets were subject to keep-whole arrangements. As of September 30, 2005, we had reduced that number to approximately 23% in the mid-continent region.

      As part of our previously planned strategy, on August 1, 2005, we suspended operations at our Lakin natural gas processing plant, reserving the right to operate it intermittently. The natural gas that would have been processed at the Lakin plant is now processed at a third party processing plant for our account for a fee. Suspending the operations of the plant allowed us to renegotiate and replace certain unfavorable keep-whole processing arrangements covering natural gas processed at the plant with fee-based contracts. Additionally, by suspending the Lakin plant, we are able to avoid charges for transporting natural gas through a third party pipeline out of the tailgate of the plant. We expect to realize a net benefit to our cash flows and earnings from the changes in addition to a reduced risk portfolio. We are actively seeking to use the 80 MMcf/d of newly available processing capacity at the plant by attempting to contract for additional supply to the plant or by moving the plant to a new location.

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      In our Gathering and Processing segment, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have, since the acquisition of Regency Gas Services LLC by the HMTF Investors, executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options (historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil). As a result, we have hedged approximately 95% of our expected exposure to NGL prices in 2006, and approximately 75% in 2007. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

      We sell natural gas on intrastate and interstate pipelines to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies and utilities. We typically sell natural gas under pricing terms related to market index. To the extent possible, we match the pricing and timing of our supply portfolio to our sales portfolio in order to lock in our margin and reduce our overall commodity price exposure. To the extent our natural gas position is not balanced, we will be exposed to the commodity price risk associated with the price of natural gas.

      Until recently, the NGLs produced by our processing plants were sold to third parties as mixed NGLs. In September 2005, we began delivering the mixed NGLs produced by our processing plants to operators of fractionation facilities for fractionation for our account. We then sell the individual components, such as ethane, propane and isobutane, directly to marketing companies, refineries and other wholesalers. We believe this marketing function will allow us to earn additional margins from the sale of the NGLs that otherwise would have been earned by the fractionator.

     Transportation Segment

      Results of operations from our Transportation segment are determined primarily by the volumes of natural gas transported on our Regency Intrastate Pipeline system and the level of fees charged to our customers or the margins received from purchases and sales of natural gas. We generate our revenues and segment margins for our Transportation segment principally under fee-based transportation contracts or through the purchase of natural gas at one of the inlets to the pipeline and the sale of natural gas at the outlet. In the latter case, we generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that natural gas at the pipeline outlet. The differential in the purchase price and the sale price contributes to our segment margin. The margin we earn from our transportation activities is directly related to the volume of natural gas that flows through our system and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices resulted in a decline in volumes, our revenues from these arrangements would be reduced.

      Generally, we provide to shippers two types of fee-based transportation services under our transportation contracts:

•  Firm Transportation. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a commodity charge with respect to quantities actually transported by us.

•  Interruptible Transportation. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped.

      We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with FERC with respect to transportation authorized under section 311 of the Natural Gas Policy Act of 1978, or NGPA.

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      In addition, we perform a limited merchant function on our Regency Intrastate Pipeline system. We purchase natural gas from a producer or gas marketer at a receipt point on our system at a price adjusted to reflect our transportation fee and transport that gas to a delivery point on our system at which we sell the natural gas at market price. We regard the segment margin with respect to those purchases and sales as the economic equivalent of a fee for our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the index price on the date of settlement.

      Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result, we have completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. This project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.

      The Regency Intrastate Enhancement Project is a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to access new sources of supply and markets. We began planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005.

      The total cost of this project is expected to be approximately $140 million, which includes the expansion of our existing Regency Intrastate Pipeline system and an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system supported by approximately 9,500 horsepower of additional compression. The project has extended our transportation services into additional major producing fields in north Louisiana and has connected our system to additional pipelines in northeast Louisiana.

      The completion of the Regency Intrastate Enhancement Project enables us to provide transportation services from the three largest natural gas producing fields in Louisiana. Prior to the completion of the final phase of the project in December 2005, we were transporting approximately 265 MMcf/d under existing contracts, including 65 MMcf/d attributable to the completion of the first two phases of the project. Additionally we have signed definitive agreements for 249 MMcf/d of firm transportation and 156 MMcf/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining incremental transportation capacity of 130 MMcf/d resulting from the Regency Intrastate Enhancement Project.

How We Evaluate Our Operations

      Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, total segment margin and operating expenses on a segment basis and EBITDA on a company-wide basis.

      Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

      To increase throughput volumes on our intrastate pipeline we must contract with shippers, including producers and marketers, for supplies of natural gas. We routinely monitor producer and marketing activities in the areas served by our transportation system to pursue new supply opportunities.

      Segment Margin. We calculate our Gathering and Processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, which also include third-party transportation and processing fees. Revenue includes

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revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing natural gas. Our contract portfolio impacts our segment margin. See “— Our Operations” for a discussion of our contract portfolio.

      We calculate our Transportation segment margin as revenue minus the cost of natural gas that we purchase and transport. Revenue primarily includes sales of pipeline-quality natural gas and fees for the transportation of pipeline-quality natural gas. Most of our segment margin is fee-based with little or no commodity price risk. We generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet. We regard the difference between the purchase price and the sale price as the economic equivalent of our transportation fee.

      Operating Expenses. Operating expenses are a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

      EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•  financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•  the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partners;

•  our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

•  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

      EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

General Trends and Outlook

      We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

      Natural Gas Supply, Demand and Outlook. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.1 trillion cubic feet, or Tcf, in 2004 to approximately 25.4 Tcf in 2010, representing an annual growth rate of over 2.3%. During the five years ending December 31, 2004, the United States has on average consumed approximately 22.6 Tcf per year, while total marketed domestic production averaged approximately 19.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

      We believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe that an increase

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in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

      All of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our operations.

      Gathering and Processing Segment Margins. For the eighteen months ended September 30, 2005, our overall portfolio of processing contracts reflected a net short position in natural gas of approximately 11,300 MMBtu/d (meaning that we were a net buyer of natural gas) and a net long position in NGLs of approximately 6,200 Bbls/d (meaning that we were a net seller of NGLs). As a result, during this period our segment margins were positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and were adversely impacted to the extent the price of NGLs declined in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. This portfolio performed well in response to favorable fractionation spreads during these periods.

      In keeping with our strategy of reducing commodity price exposure, however, we have adjusted our contract portfolio through renegotiation of certain keep-whole contracts, including three large keep-whole contracts that were converted to fee contracts in August 2005, resulting in a shift of our overall natural gas position to a slightly long position going forward, while retaining a long physical NGL position. We believe that this adjusted portfolio effectively hedges our overall exposure to volatility in fractionation spreads. Our profitability is now positively impacted if natural gas or NGLs prices increase and negatively impacted if natural gas and NGLs prices decrease. The prices of natural gas and NGLs are volatile and beyond our control.

      Impact of Interest Rates and Inflation. The credit markets recently have experienced 50-year record lows in interest rates. If the overall economy continues to strengthen, we believe that it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

      Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2004 or the nine months ended September 30, 2005. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Formation, Acquisition and Asset Disposal History and Financial Statement Presentation

     Our Formation of Regency Energy Partners LP and the Initial Public Offering

      We are a Delaware limited partnership formed in September 2005 to own and operate Regency Gas Services LLC. Prior to this offering, Regency Gas Services LLC has been owned by the HMTF Investors. In connection with the consummation of this offering, Regency Gas Services LLC, will be converted into a limited partnership named Regency Gas Services LP, and will be contributed to us by the HMTF Investors in exchange for 5,353,896 common units, 19,103,896 subordinated units, the incentive distribution rights, a continuation of its 2% general partner interest in us, and a right to receive $197.0 million of proceeds from this offering in reimbursement of a corresponding amount of capital expenditures comprising most of the initial investment by the HMTF Investors in Regency Gas Services LLC. In addition, approximately $48.0 million in cash and accounts receivable will be distributed by

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Regency Gas Services LLC to the HMTF Investors prior to Regency Gas Services LLC being contributed to us and will be replenished with proceeds from the offering.

      At the closing of this offering and the related formation transactions:

•  we will issue 13,750,000 common units to the public in this offering, representing a 35.3% limited partnership interest in us;

•  the HMTF Investors will own 5,353,896 common units and 19,103,896 subordinated units, totaling an aggregate 62.7% limited partner interest in us;

•  the HMTF Investors will own all of the equity interests in our general partner, Regency GP LP;

•  Regency GP LP will own the 2% general partner interest in us as well as the incentive distribution rights;

•  we will own all of the ownership interests in Regency Gas Services LP, our operating partnership, and its operating subsidiaries, which will own and operate our assets;

•  we will pay $9.0 million to an affiliate of Hicks Muse as consideration for the termination of ten-year financial advisory and monitoring and oversight agreements between the affiliate of Hicks Muse and us. These agreements would have required us to pay to the affiliate of Hicks Muse certain management fees and transaction advisory fees in the future, which would decrease our cash available for distribution; and

•  we will enter into an omnibus agreement with Regency Acquisition LP, an affiliate of the HMTF Investors, pursuant to which Regency Acquisition LP will agree to indemnify us for certain environmental liabilities, tax liabilities and title and right-of-way defects occurring or existing before the closing.

     The HMTF Investors’ Acquisition of Regency Gas Services LLC

      On December 1, 2004, the HMTF Investors acquired all of the outstanding equity interests in Regency Gas Services LLC from its previous owners. The HMTF Investors accounted for this acquisition as a purchase, and purchase accounting adjustments, including goodwill and other intangible assets, have been “pushed down” and are reflected in the financial statements of Regency Gas Services LLC for the period subsequent to December 1, 2004. Regency Gas Services LLC is designated as the “Regency LLC Predecessor” or “Predecessor” in our consolidated financial statements for the periods ended before December 1, 2004.

     Formation of Regency Gas Services LLC

      Regency Gas Services LLC was organized on April 2, 2003 by a private equity fund for the purpose of acquiring, managing and operating natural gas gathering, processing and transportation assets. Regency Gas Services LLC had no operating history prior to the acquisition of the El Paso assets and the Duke Energy Field Services assets discussed below.

     Acquisition of El Paso Assets

      General. On June 2, 2003, Regency Gas Services LLC acquired certain natural gas gathering, processing and transportation assets from subsidiaries of El Paso Corporation for approximately $119.5 million. The assets acquired consisted of gathering, processing and transportation assets located in north Louisiana and gathering and processing assets located in the mid-continent region of the United States and represent substantially all of our existing north Louisiana and mid-continent assets. At the time of the acquisition, the acquired gathering and transportation systems had an average expected remaining useful life of approximately 20 years and the processing plants had an average expected remaining useful life of approximately 15 years.

      Changes in Operations and Commercial Relationships. Prior to our acquisition of these assets, these assets were operated as components of El Paso’s much larger midstream operations. Immediately following our acquisition of these assets, we changed the manner in which these assets were operated. In that regard, we initiated, and continue to implement, a strategy to reshape the revenue structure of the acquired assets

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to expand revenues, increase margins and decrease exposure to market volatility. Our prompt elimination of significant affiliate transactions, the restructuring of contracts to limit commodity risk exposure and other changes quickly made our business regarding these assets very different from El Paso’s.

      During El Paso’s ownership of these assets, sales of natural gas and NGLs were typically made to affiliates of El Paso, natural gas was typically transported from the assets on El Paso affiliated pipelines under affiliate agreements and facilities and personnel were often shared. Furthermore, the scheduling and dispatch responsibilities for these assets were managed by El Paso’s central control facility. We believe that, immediately prior to the acquisition, nearly 50% of the total revenues being generated by these assets was derived from transactions with affiliates of El Paso. To the extent that these related party transactions were effected pursuant to contracts, we did not assume the contracts. Immediately after the transaction, however, we commenced an aggressive marketing program and, in less than two months, had replaced most of this El Paso affiliate revenue with revenue generated from many new third-party customers. By December 2003, we had replaced virtually all revenues derived from transactions with El Paso affiliates.

      We have also renegotiated a significant portion of the producer supply contracts relating to these assets to decrease our exposure to commodity risk associated with keep-whole contracts. Immediately following the acquisition of these assets, we terminated virtually all of the significant month-to-month keep-whole contracts and replaced them with fee-based or percent-of-proceeds contracts. Moreover, we have replaced and continue to replace our longer term keep-whole contracts as they expire or whenever the opportunity presents itself. At the time of this asset acquisition, 71%, by volume, of the mid-continent gathering and processing contracts were keep-whole contracts. We reduced that number to approximately 23% by September 30, 2005.

      Changes in management and employees. We did not hire any of El Paso’s senior management with respect to these assets. In connection with the north Louisiana assets, we hired approximately 20 field operating employees, one accountant, one project development employee, one environmental employee and one sales employee who were formerly employed by El Paso. In connection with the mid-continent assets, we hired approximately 40 field operating employees and one accountant. We did not hire any other El Paso employees associated with the assets. For a two-month period, El Paso committed to provide us with transition services. We immediately hired a chief accounting officer and several employees to provide us with an accounting function. In addition, promptly after the acquisition, we entered into a number of outsourcing agreements with third parties under which they provided us with contract administration, nominations and scheduling, payroll, human resources and employee benefits. We also entered into additional outsourcing agreements to obtain the research, design and implementation services to install the information technology essential to the generation of financial and other critical information relating to the operation of the assets. Over time, we have hired additional non-El Paso employees who have enabled us to discontinue much of these outsourcing arrangements this year.

      Changes in operating procedures and systems. We did not acquire any information systems with the assets. All critical operating and financial information systems were replaced. We implemented different information systems to account for and manage the assets. Specifically, these different systems include the following: financial accounting; measurement; scheduling and nominations; and producer disbursements. These information systems replaced different systems used by El Paso.

     Acquisition of Duke Energy Field Services Assets

      General. On March 1, 2004, Regency Gas Services LLC acquired certain natural gas gathering and processing assets from Duke Energy Field Services, LP for approximately $67.3 million, including transactional costs. The assets acquired consisted of gathering and processing assets located in west Texas and represent substantially all of our existing west Texas assets. At the time of the acquisition, the acquired gathering systems had an average expected remaining useful life of approximately 20 years and the acquired processing plant had an expected remaining useful life of approximately 15 years.

      Changes in operations and commercial relationships. Prior to our acquisition of these assets, these assets were operated as components of Duke Energy Field Services’ much larger midstream operations. As with the assets acquired from El Paso, immediately following our acquisition of these assets, we

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implemented significant operational changes designed to expand revenues, increase margins and limit exposure to market volatility. We promptly changed the manner in which pipeline-quality natural gas was marketed from these assets by extending contract terms.

      Prior to the acquisition, pipeline-quality natural gas and NGLs produced by the Waha processing plant were pooled with the output of Duke Energy Field Services’ other processing plants and then marketed by Duke Energy Field Services or one of its affiliates. The allocation of revenues to individual plants was based on average prices received over particular time frames (with no identification of price to source of quantities of the natural gas or NGLs). Most of the natural gas and NGLs were sold for the accounts of producers under percent-of-proceeds or fee-based processing contracts. To the extent that the pooling arrangement resulted in a favorable price for the pipeline-quality natural gas and NGLs, the producers enjoyed a large part of the benefit. In turn, the arrangements constituted an incentive for the producers to commit greater volumes of raw natural gas to the system.

      Without the benefit of the natural gas and NGL pools and Duke Energy Field Services’ transportation pipeline interconnects, we were immediately required to adopt a different set of marketing strategies more suitable for a point to point marketer. These strategies included efforts to expand greatly the number of natural gas sales customers and to attract gas sales customers by offering longer-term contracts at beneficial prices.

      Upon acquisition of the assets, we immediately altered the marketing strategy of the pipeline-quality natural gas produced from these assets. Although Duke Energy Field Services sold 100% of the pipeline-quality natural gas under month-to-month contracts, we altered those arrangements in order to sell a portion of such natural gas under longer term contracts (a majority of which have one year terms). We believe that this results in different margin and revenue opportunities than those afforded by Duke Energy Field Services’ sales procedure.

      Changes in management and employees. As in the case of the El Paso assets, we did not hire any of Duke Energy Field Services’ management team. We hired 35 field operating employees from Duke Energy Field Services. As a result, we continued to outsource our gas scheduling and dispatch, as well as contract administration, expanding those required services to cover the acquired assets. This approach was in contrast to Duke Energy Field Services’ centralized internal administration of scheduling, dispatch and contract administration.

      Changes in operating procedures and systems. We did not acquire information systems with the assets. The operation of these assets was merged with the operations monitored by the information systems installed by us in connection with the acquisition of the El Paso assets. These information systems replaced the following information systems previously used by Duke Energy Field Services in connection with the acquired assets: financial accounting, measurement, scheduling and nominations, and producer disbursements.

     Other Acquisition and Asset Disposal History

      Acquisition and Sale of Cardinal Assets. On April 1, 2004, we completed the purchase of gas processing interests located in Louisiana and Texas from Cardinal Gas Services LLC for $3.5 million of cash. On May 2, 2005, we sold all of the assets acquired from Cardinal, together with certain related assets, for $6.0 million. After the allocation of $0.9 million of goodwill, the resulting gain was $0.6 million. We have treated Cardinal as a discontinued operation.

     Nature of El Paso and Duke Energy Field Services Asset Acquisitions

      The rules of the Securities and Exchange Commission generally require a company that has acquired a significant “business” within a prescribed time period prior to a public offering to include pre-acquisition financial statements of the acquired business in the prospectus used in connection with the public offering. In general, the term “business” is required to be evaluated in light of the facts and circumstances involved and whether there is sufficient continuity of the acquired entity’s operations prior to and after the transaction such that disclosure of prior financial information is material to an understanding of future operations.

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      We believe the acquisitions of assets from El Paso and Duke Energy Field Services described above do not represent the acquisition of “businesses,” within the meaning of these requirements, but rather the acquisition of assets. Each of the acquisitions was structured as an acquisition of assets. We did not acquire any entities, subsidiaries or divisions of El Paso or Duke Energy Field Services, other than Gulf States Transmission Corporation, which was acquired in the acquisition of the El Paso assets. Gulf States Transmission Corporation only owned a single asset, that being a ten-mile length of interstate pipeline. Furthermore, for the reasons discussed above, as a result of the significant changes in operations, commercial relationships, management, employees, operating procedures and systems relating to the assets, we believe that there was not sufficient continuity of the acquired asset’s operations prior to and after the transactions to make disclosure of the prior financial information of the assets material to an understanding of the operations of the assets after the acquisition.

      Since we have concluded that the acquisitions of the El Paso assets and the Duke Energy Field Services assets do not constitute the acquisition of businesses, we have not provided stand-alone pre-acquisition financial statements for the assets acquired.

Items Impacting Comparability of Our Financial Results

      Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward, for the reasons described below:

•  Regency Gas Services LLC commenced operations in June 2003 with the acquisition of the El Paso assets. As a result, we do not have any material financial results for periods prior to June 2003 and our results of operations for the period ended December 31, 2003 includes only seven months of financial results.

•  Regency Gas Services LLC acquired the Duke Energy Field Services assets in March 2004. As a result, our financial results for periods prior to March 2004 do not include the financial results of the Duke Energy Field Services’ assets.

•  In connection with the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004, the purchase price was “pushed-down” to the financial statements of Regency Gas Services LLC. As a result of this “push-down” accounting, the book basis of our assets was increased to reflect the purchase price, which had the effect of increasing our depreciation and amortization expense. Also, the increased level of debt incurred in connection with the acquisition increased our interest expense subsequent to December 1, 2004.

•  We anticipate incurring approximately $2.5 million of additional general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance costs, independent auditor fees, investor relation expenses, registrar and transfer agent fees.

•  In December 2004 we undertook a hedging program as required by our credit facilities. Effective July 1, 2005 we designated certain commodity and interest rate swap instruments for hedge accounting treatment in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For the periods from December 1, 2004 through June 30, 2005 unrealized and realized gains and losses on the commodity swaps were recorded in unrealized/realized gain (loss) from risk management activities in our statements of operations. For the six months ended June 30, 2005 unrealized gains and losses on the interest rate swap were recorded in interest expense, net. Effective July 1, 2005, to the extent the hedges are effective, any unrealized gains or losses on these instruments were recorded in other comprehensive income (loss) during the lives of the instruments, which we believe will lead to financial results that are not comparable for the affected periods.

•  We completed a major enhancement of our Regency Intrastate Pipeline system in December 2005. The planning of this project commenced in January 2005 and construction began in May 2005. The

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total cost of this project is expected to be approximately $140 million and the project is expected to provide significant additional throughput volumes and cash flow.

Critical Accounting Policies and Estimates

      Conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

      Revenue and Cost of Sales Recognition. We record revenue and cost of sales on the gross basis for those transactions where we act as the principal and take title to gas that is purchased for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues.

      We currently record the monthly results of operations using actual results which include settling most of our volumes with producers, shippers and customers around the 25th of the month following the production month. This process results in a delay in reporting results. To conform to industry practice, we will implement a closing process that eliminates the reporting lag. Prior to the settlement date, we will record actual operating data as available, such as actual operating and maintenance and other expenses. For total segment margin, we will estimate settlements using actual pricing and estimated volumes. In the subsequent production month, we will reconcile the estimates to the actual results and record the difference. This new process may result in variances from actual. The new process expedites financial reporting and conforms with industry practice.

      Risk Management Activities. In order to protect ourselves from commodity and interest rate risk, we pursue hedging activities to minimize those risks. These hedging activities rely upon forecasts of our expected operations and financial structure over the next four years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.

      From the inception of our hedging program in December 2004 through June 30, 2005, we used mark-to-market accounting for our commodity and interest rate swaps as well as for crude oil puts. For the one month ending December 31, 2004, the amount of net realized and unrealized gains was $0.3 million. For the nine months ended September 30, 2005, we incurred $19.7 million of realized and unrealized net losses, $7.4 million of which was realized and $12.3 million of which was unrealized. The $12.3 million is comprised of $12.7 million of net losses related to commodity hedges which are reflected in operating revenues and $0.4 million of net gains related to interest rate hedges which are reflected in interest expense, net. We record realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses monthly based upon the future value of the hedges through their expiration dates. The expiration dates vary but are currently no later than December 2007. We monitor and review hedging positions regularly. Effective July 1, 2005, we elected to use hedge accounting for the swap contracts. We believe that the prospective application of cash flow hedge accounting for the swap transactions will mitigate the volatility in our earnings. If we had adopted hedge accounting for these swaps at the inception of our hedging program, our net income for the one month ended December 1, 2004 and for the nine months ended September 30, 2005 would have been $0.8 million lower and $6.3 million higher, respectively. We base these results upon the assumptions of perfectly matched terms between the swaps and the forecasted hedged transactions with respect to commodity, volumes, delivery points, delivery periods, and the price index used for settlement. Further, the results assume the designation of the swaps as cash flow hedges at their inception.

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      Purchase Accounting. On December 1, 2004, we were acquired by the HMTF Investors. We made various assumptions in determining the fair values of acquired assets and liabilities. In order to allocate the purchase price to the business units, we developed fair value models with the assistance of outside consultants. These fair value models applied discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. An economic value was determined for each business unit. The total economic value was equal to the purchase price. We then determined the fair value of the fixed assets was based on estimates of replacement costs. We identified intangible assets related to licenses and permits, and renegotiated customer contracts and assigned a fair value of $18.5 million. We made assumptions regarding the period of time it would take to replace these permits. We assigned value using a lost profits model over that period of time necessary to replace the permits. The customer contracts were valued using a discounted cash flow model. We determined liabilities assumed based on their expected future cash outflows. We recorded the excess of the cost of each business unit over the sum of amounts assigned to the tangible assets, financial assets, and separately recognized intangible assets acquired less liabilities assumed of the business unit, as goodwill which amounted to $58.5 million.

      Depreciation Expense and Cost Capitalization Policies. Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipeline. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. The cost of funds used in construction represents capitalized interest used to finance the construction of new facilities. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.

      As discussed in the Notes to the Consolidated Financial Statements, depreciation of the Company’s assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

      The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

      Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. To date, we have not recorded any liability for remediation expenses and we do not believe that any significant liability currently exists. If governmental regulations change, we could be required to incur remediation costs that might have a material impact on our profitability.

      Additionally, we had no actual or conditional asset retirement obligations under Statement of Financial Accounting Standards (SFAS) No. 143 “Accounting for Asset Retirement Obligations” for any period presented.

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Results of Operations

Nine Months Ended September 30, 2005 vs. Nine Months Ended September 30, 2004

      The table below contains key company-wide performance indicators related to our discussion of the results of operations.

	Regency Gas			Regency LLC
	Services LLC			Predecessor
	Nine Months Ended
	September 30,
	2005			2004			$ Change			% Change
				($ in millions)
Revenues(a)	$	434.6		$	339.1		$	95.5			28	%
Cost of sales		386.9			286.0			100.9			35
Total segment margin(b)		47.7			53.1			(5.4	)		(10	)
Operating expenses		15.5			13.7			1.8			13
General and administrative		9.6			5.3			4.3			81
Depreciation and amortization		15.7			8.1			7.6			94
Operating income		6.9			26.0			(19.1	)		(73	)
Interest expense, net		(12.7	)		(4.1	)		(8.6	)		210
Loss on debt refinancing		(7.7	)		(1.4	)		(6.3	)		450
Other income and deductions, net		0.2			—			0.2			n/m
Net (loss) income from continuing operations		(13.3	)		20.5			(33.8	)		(165	)
Discontinued operations		0.7			—			0.7			n/m
Net (loss) income	$	(12.6	)	$	20.5		$	(33.1	)		(161	)%
System inlet volumes (MMBtu/d)(c)		557,367			484,845			72,522			15	%
Processing volumes (MMBtu/d)		228,914			228,211			703			0

(a)	2005 revenues include a net unrealized loss from risk management activities of $12.7 million.
(b)	For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Summary — Non-GAAP Financial Measures.”
(c)	System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

n/m = not meaningful

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      The table below contains key segment performance indicators related to our discussion of the results of operations.

				Regency Gas		Regency LLC
				Services LLC		Predecessor
				Nine Months Ended
				September 30,
				2005		2004		$ Change			% Change
						($ in millions)
Segment Financial and Operating Data:
	Gathering and Processing Segment Financial data:
			Segment margin(a)	$	37.6	$	46.2	$	(8.6	)		(19	)%
			Operating expenses		14.2		12.5		1.7			14
		Operating data:
			Throughput (MMcf/d)		284		272		12			4
			NGL gross production (Bbls/d)		14,824		13,841		983			7
Transportation Segment
	Financial data:
			Segment margin	$	10.1	$	6.9	$	3.2			46	%
			Operating expenses		1.3		1.2		0.1			8
	Operating data:
			Throughput (MMcf/d)		232		177		55			31

(a)  2005 segment margin includes a net unrealized loss from risk management activities of $12.7 million.

      Net Income. Net income for the nine months ended September 30, 2005 decreased $33.1 million compared with the same period in 2004. Interest expense, net increased $8.6 million primarily due to higher net interest expense related to debt incurred to fund the HMTF Transaction. Depreciation and amortization expense increased $7.6 million primarily due to our higher depreciable basis following purchase accounting for the HMTF Transaction. In the nine months ended September 30, 2005 we wrote off $7.7 million of debt issuance costs (consisting of $5.8 million of unamortized debt issuance costs and $1.9 million paid in July 2005 in connection with the amendment of our credit facilities). In the period ended September 30, 2004, we wrote off $1.4 million of unamortized debt issuance costs. The decrease in net income also included a reduction in total segment margin of $5.4 million, which included a $12.7 million net unrealized loss and a $7.2 million realized loss from risk management activities. General and administrative expense increased $4.3 million primarily as a result of higher employee-related expenses. Operating expenses increased $1.8 million primarily due to our west Texas facilities operating nine months in 2005 versus seven months in 2004 and higher taxes, other than income.

      During the nine months ended September 30, 2005, we realized losses of $7.2 million on risk management activities. This loss consists of $5.9 million of swap settlements and $1.3 million of premiums associated with expired crude put options which were paid in a prior period. As noted below, these amounts were more than offset by a positive price variance of $7.4 million, demonstrating the effectiveness of our hedging program with respect to stabilizing the cash generated by the sale of our NGLs.

      Total Segment Margin. Total segment margin for the nine months ended September 30, 2005 decreased to $47.7 million from $53.1 million for the same period in 2004, representing a 10% decline. Unrealized and realized losses from risk management activities reduced total segment margin for the nine months ended September 30, 2005 by $19.9 million, of which $12.7 million represented net unrealized, non-cash losses reflecting the change in the fair value of derivative contracts for the periods. Please read

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“— Critical Accounting Policies and Estimates” for a detailed discussion of this matter. The following positive elements offset, in part, this reduction in total segment margin:

•  $3.9 million of total segment margin attributable to our west Texas assets which we operated for the entire nine months ended September 30, 2005 as compared to only seven months during the 2004 comparison period,

•  $7.4 million of increased total segment margin attributable to higher commodity prices and

•  $3.2 million of total segment margin attributable to increased pipeline throughput volumes.

      Segment margin for the Gathering and Processing Segment for the nine months ended September 30, 2005 decreased to $37.6 million from $46.2 million for the same period in 2004, representing a 19% decline. Unrealized and realized losses from risk management activities reduced total segment margin for the nine months ended September 30, 2005 by $19.9 million, of which $12.7 million represented net unrealized, non-cash losses reflecting the change in the fair value of derivative contracts for the period. The following positive elements offset, in part, this reduction in segment margin:

•  $3.9 million of segment margin attributable to our west Texas assets which we operated for the entire nine months ended September 30, 2005 as compared to only seven months during the 2004 comparison period and

•  $7.4 million of increased segment margin attributable to higher commodity prices.

      Segment margin for the Transportation segment for the nine months ended September 30, 2005 increased to $10.1 million from $6.9 million for the comparable period in 2004, a 46% increase. The increase was attributable to increased throughputs across the system in 2005.

      Operating Expenses. Operating expenses for the nine months ended September 30, 2005 increased to $15.5 million from $13.7 million for the same period in 2004, representing a 13% increase. This increase primarily resulted from the operation of our west Texas assets in the Gathering and Processing Segment for the full nine months ended September 30, 2005 as compared to seven months in 2004. Higher taxes, other than income, primarily property taxes in the mid-continent region within the Gathering and Processing Segment, resulted in an increase of $0.7 million.

      General and Administrative. General and administrative expense increased to $9.6 million in the nine months ended September 30, 2005 from $5.3 million for the same period in 2004. This increase was primarily attributable to higher employee-related expenses of $2.5 million, including higher salary expense associated with increased headcount and bonus accruals. Also contributing to the increase were increased professional and consulting expenses of $1.0 million, consisting primarily of legal fees for regulatory and contract related matters, business development and consulting fees for Sarbanes-Oxley compliance support. Further contributing to the increase were higher management fees of $0.5 million, resulting from our relationship with Hicks Muse, and increased insurance costs of $0.2 million.

      Depreciation and Amortization. Depreciation and amortization increased to $15.7 million in the nine months ended September 30, 2005 from $8.1 million for the same period in 2004, representing a 94% increase. Depreciation expense increased $6.2 million primarily due to the acquisition of Regency Gas Services LLC by the HMTF Investors in December 2004, which increased the book basis of our depreciable assets to their fair market value. Also contributing to the increase was the amortization of identifiable intangible assets of $1.4 million in the 2005 period related to purchase accounting following the HMTF Transaction.

      Interest Expense, Net. Interest expense, net increased $8.6 million, or 210%, in the nine months ended September 30, 2005 compared to the same period in 2004 due to higher net interest expense of $7.9 million, primarily related to debt incurred to fund the HMTF Transaction, and increased amortization of debt issuance costs of $0.7 million.

      Loss on Debt Refinancing. In the nine months ended September 30, 2005 and September 30, 2004, we wrote-off $7.7 million and $1.4 million, respectively, of debt refinancing costs related to our amended

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credit facilities in accordance with EITF 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instruments.” The $7.7 million write-off consisted of $5.8 million of unamortized debt issuance costs and $1.9 million paid in July 2005 in connection with the amendment of our credit facilities. The write-off for the nine months ended September 30, 2004 consisted of unamortized debt issuance costs.

      Federal Income Tax. As a pass-through entity, we are not subject to federal income taxes. Our member incurs the liability for federal income taxes associated with our business.

      Discontinued Operations. On April 1, 2004, we completed the purchase of natural gas processing and treating interests located in Louisiana and Texas from Cardinal for $3.5 million. On May 2, 2005, we sold all of the assets acquired from Cardinal, together with certain related assets, for $6.0 million. The results of Cardinal are presented as discontinued operations, and we recorded a gain on the sale of $0.6 million during the nine months ended September 30, 2005.

      See Note 2 to the accompanying consolidated financial statements and “Formation, Acquisition and Asset Disposal History and Financial Statement Presentation” above for additional information on Cardinal.

The Month of December 2004

      The HMTF Investors purchased Regency Gas Services LLC effective December 1, 2004. As a result of accounting for the acquisition as a purchase and using push-down accounting, we incurred additional depreciation and amortization expense. Depreciation and amortization expense for this one month increased over the preceding monthly amount by $0.6 million or 61% resulting from the “step-up” in basis of tangible assets as well as the recording of new identifiable intangible assets from the purchase price allocation. The additional interest expense resulted primarily from higher levels of borrowings associated with the acquisition. These levels of borrowings increased to $250.0 million at December 31, 2004 from $66.6 million at December 31, 2003.

Period from January 1, 2004 to November 30, 2004 vs. Period from Inception (April 2, 2003) to December 31, 2003

      The table below contains key company-wide performance indicators related to our discussion of the results of operations.

	Regency LLC
	Predecessor			Regency Gas
				Services LLC
	Period from
	Inception			Period from
	(April 2, 2003) to			January 1, 2004 to
	December 31, 2003			November 30, 2004			$ Change			% Change
	($ in millions)
Revenue	$	186.5		$	432.3		$	245.8			132	%
Cost of sales		163.4			362.7			199.3			122
Total segment margin(a)		23.1			69.6			46.5			201
Operating expenses		7.0			17.8			10.8			154
General and administrative		2.7			6.6			3.9			144
Transaction expenses		0.7			7.0			6.3			900
Depreciation and amortization		4.3			10.1			5.8			135
Operating income		8.4			28.1			19.7			235
Interest expense, net		(2.4	)		(5.1	)		(2.7	)		113
Loss on debt refinancing		—			(3.0	)		(3.0	)		n/m
Other income and deductions, net		0.2			0.1			0.1			50
Net income from continuing operations		6.2			20.1		$	13.9			224
Discontinued operations		—			(0.1	)		(0.1	)		n/m
Net income	$	6.2		$	20.0		$	13.8			223	%

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	2003		2004		Change		% Change
System inlet volumes (MMBtu/d)(b)		423,043		495,581		72,538		17	%
Processing volumes (MMBtu/d)		136,127		237,247		101,120		74

(a)  For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Summary — Non-GAAP Financial Measures.”

(b) System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

n/m = not meaningful

      The table below contains key segment performance indicators related to our discussion of the results of operations.

					Regency LLC
					Predecessor		Regency Gas
							Services LLC
					Period from
					Inception		Period from
					(April 2, 2003) to		January 1, 2004 to
					December 31, 2003		November 30, 2004		$ Change			% Change
					($ in millions)
Segment Financial and Operating Data:
	Gathering and Processing segment
		Financial data:
			Segment margin		$	18.9	$	61.4	$	42.5			225	%
			Operating expenses			6.1		16.2		10.1			166
		Operating data:
			Throughput (MMcf/d)			199		279		80			40
				NGL gross production (Bbls/d)		9,434		14,487		5,053			54
	Transportation segment
		Financial data:
			Segment margin		$	4.2	$	8.2	$	4.0			95	%
			Operating expenses			0.9		1.6		0.7			78
		Operating data:
			Throughput (MMcf/d)			197		179		(18	)		(9	)

      Results of operations for the year ended December 31, 2003 comprise the period from inception from April 2, 2003 through December 31, 2003; however, the period included only seven months of active operations which began on June 2, 2003.

      Net Income. Net income for the eleven months ended November 30, 2004 increased $13.8 million compared with the seven months of active operations in 2003. Net income was significantly enhanced due to the contribution of $22.1 million of segment margin related to the purchase of the west Texas assets in 2004. Interest expense, net increased $2.7 million primarily due to higher net interest expense related to debt incurred to fund the west Texas assets acquisition. In the eleven months ended November 30, 2004, we wrote off $3.0 million of debt issuance costs in connection with the amendment of our current credit facilities and the repayment of our prior facility. Depreciation and amortization expense increased $5.8 million primarily due to our higher depreciable basis following the purchase of the west Texas assets. General and administrative expense increased $3.9 million primarily as a result of higher employee-related expenses and professional and consulting expenses. Operating expenses increased $10.8 million primarily due to our west Texas facilities operating seven months in 2004 versus none in the 2003 period and the difference of four more months in the comparable periods.

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      Total Segment Margin. Total segment margin for the eleven months ended November 30, 2004 increased to $69.6 million from $23.1 million for the seven months of active operations in 2003, a 201% increase. Of this increase:

•  $22.1 million was produced by operating assets acquired in west Texas in March of 2004;

•  $14.5 million was attributable to the operation of our north Louisiana and mid-continent assets, which were acquired in June 2003, for eleven months in the 2004 period compared with seven months of active operations in 2003 period;

•  $0.7 million resulted from NGL marketing operations, which were present in the eleven months ended November 30, 2004 but absent in the seven months of active operations in 2003; and

•  the remaining $9.2 million resulted from increased margins per unit of throughput.

      Segment margin for the Gathering and Processing segment increased to $61.4 million for the eleven months ended November 30, 2004 from $18.9 million for the seven months of active operations in 2003, a 225% increase. Of this increase:

•  $22.1 million was produced by operating assets acquired in west Texas in March of 2004;

•  $12.1 million was attributable to the operation of our north Louisiana and mid-continent gathering and processing assets, which were acquired in June 2003, for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period;

•  $0.7 million was attributable to NGL marketing operations; and

•  the remaining $7.6 million resulted from increased margins per unit of throughput, primarily as a result of commodity price changes.

      Segment margin for the Transportation segment increased to $8.2 million for the eleven months ended November 30, 2004 from $4.2 million for the seven months of active operations in 2003, a 95% increase. Of this increase:

•  $2.4 million was attributable to operation of the assets for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period; and

•  $1.5 million was attributable to increased margins per unit of throughput, primarily as a result of changes in contract mix in 2004.

      Operating Expenses. Operating expenses for the eleven months ended November 30, 2004 increased to $17.8 million from $7.0 million in the seven months ended of active operations in 2003, a 154% increase. The addition of the west Texas assets to our Gathering and Processing segment accounted for $6.5 million of the increase. The remaining increase is attributable to operations for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period, with $3.6 million of the increase resulting from our Gathering and Processing segment and $0.7 million of the increase resulting from our Transportation segment.

      General and Administrative Expense. General and administrative expense increased to $6.6 million in 2004 from $2.7 million in 2003, a 144% increase. The increase is primarily attributable to employee related expenses of $2.1 million and professional and consulting expenses of $1.3 million. The employee related expenses and the professional and consulting expenses were impacted by the eleven months of expense in 2004 versus seven months of active operations in 2003 as well as an increase in payroll expense in 2004 associated with our west Texas assets.

      Transaction Expense. Regency LLC Predecessor incurred internal non-recurring expenses related to the sale of Regency Gas Services LLC to the HMTF Investors in the amount of $7.0 million in 2004. These expenses consist of compensation, legal and other expenses and were paid by Regency LLC Predecessor prior to the HMTF Investors’ acquisition. In 2003, we incurred $0.7 million of legal and other organization expenses related to the formation of Regency LLC Predecessor.

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      Depreciation and Amortization. Depreciation and amortization increased to $10.1 million in 2004 from $4.3 million in 2003, a 135% increase. In 2004, depreciation expense of $3.0 million was associated with our west Texas assets in the Gathering and Processing segment. The remaining increase in depreciation and amortization expense results from eleven months of expense in 2004 versus seven months of active operations in 2003, primarily in the non-west Texas portion of the Gathering and Processing segment.

      Interest Expense, Net. Interest expense increased $2.7 million or 113% in 2004 compared to 2003 primarily due to the increased level of borrowings, which were used to finance acquisitions and provide the necessary working capital for the larger enterprise.

      Loss on Debt Refinancing. We expensed approximately $3.0 million of unamortized debt issuance costs upon the March 1, 2004 amendment and the December 1, 2004 repayment of our prior credit facility.

      Federal Income Tax. We are a limited partnership. Accordingly, we are not subject to federal income taxes. Our partners incur the liability for federal income taxes associated with our business.

Other Matters

      Hurricane Katrina and Hurricane Rita. Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of our assets in the region. The storms have negatively affected the nation’s short term energy supply and natural gas and NGL prices have increased significantly. We expect these higher commodity prices to have a favorable net effect on our results of operations, as we are a net seller of these commodities.

      While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to our facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area. As a result of these disruptions, we were forced temporarily to curtail certain of our producers in the west Texas region for approximately four days and to operate our north Louisiana processing assets in a reduced recovery mode for approximately six days. We do not expect ongoing effects from these temporary disruptions and neither hurricane altered our completion of the Regency Intrastate Enhancement Project.

      Environmental. A Phase I environmental study was performed on our west Texas assets by an environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2004. The study indicated that most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, an environmental pollution liability insurance policy has been acquired to cover any undetected or unknown pollution discovered in the future. The policy pays for clean-up costs and damages to third parties and has a ten-year term with a $10 million limit subject to certain deductibles.

      In March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent us a notice of violation, alleging that we are operating the Mocane processing plant in Beaver County, Oklahoma in violation of the National Emission Standard for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities, or NESHAP, and the requirements to apply for and obtain a federal operating permit (Title V permit). We believe that the basis for the allegations identified in the notice of violation is inapplicable to the Mocane processing plant. If the allegations in the notice of violation ultimately prove to be valid, we could be required to pay a penalty and to implement additional air quality emission controls at the Mocane processing plant, which may include principally a more stringent leak detection and repair program and a program of periodic compliance reports. We do not believe resolution of this notice of violation will have any materially adverse effect on our consolidated results of operations.

85

      In November 2004, the Texas Commission on Environmental Quality, or TCEQ, sent a Notice of Enforcement, or NOE, to us relating to the operation of the Waha processing plant in 2001 before it was acquired by us. We settled this NOE with the TCEQ in November 2005.

      Absent the physical or operational changes at the Waha processing plant that allegedly occasioned the NOE, the air emissions at the plant would have been limited, based on the plant’s “grandfathered” status under the relevant federal statutory standards, only by historical amounts until 2007. In anticipation of the expiration of that status and regardless of the outcome of the NOE, we submitted to the TCEQ in early February 2005 an application for a state air permit for emissions from the Waha plant predicated on the construction of an acid gas reinjection well and, after completion of the well, the reinjection of the emitted gases. That permit has been issued and requires completion of construction of the well by the end of February 2007. We estimate capital expenditures relating to the well to be $3.5 million.

Liquidity and Capital Resources

      Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners and borrowings under our credit facilities.

      Following the completion of this offering, we expect our sources of liquidity to include:

•  cash generated from operations;

•  borrowings under our credit facilities;

•  debt offerings; and

•  issuance of additional partnership units.

      We believe that the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures for the next twelve months.

Cash Flows and Capital Expenditures

      Since the inception of Regency’s operations in June 2003 through September 30, 2005, there have been several key events that have had major impacts on our cash flows. They are:

•  the acquisition of the El Paso assets on June 2, 2003 in the amount of approximately $119.5 million which was financed through equity of $53.7 million and debt of $70 million;

•  the Waha acquisition on March 1, 2004 for $67.3 million of cash and $1 million of assumed liabilities. We financed this acquisition with $10 million of new equity with the balance in debt;

•  the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004 for approximately $414 million, net of working capital adjustments, which was funded primarily through $243 million of term notes and $171 million of equity; and

•  the start up of our $140 million Regency Intrastate Enhancement Project in May 2005 which for the nine month period ended September 30, 2005 was financed through cash flows from operations, long-term debt and an equity contribution.

      Working Capital (Deficit). Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was $(5.5) million at December 31, 2003, $1.9 million at December 31, 2004 and $(15.3) million at September 30, 2005.

      The net increase in working capital from December 31, 2003 to December 31, 2004 of $7.4 million resulted primarily from the following factors:

•  an increase in cash and cash equivalents of $1.7 million;

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•  a $2.8 million increase in the value of risk management assets, resulting from the purchase of calendar 2005 crude oil put options for $2.0 million that we partially funded with an equity investment, and from a $0.8 million unrealized increase in the value of NGL swap contracts;

•  a $9.2 million reduction in the amount of short-term debt partially offset by;

•  both accounts receivable and accounts payable increased from 2003 to 2004 due to the addition of the west Texas operations in March 2004 resulting in a net $6.6 million decrease.

      The net decrease in working capital from December 31, 2004 to September 30, 2005 of $17.2 million resulted from three primary factors:

•  an $8.5 million decrease in the net of accounts receivable and accounts payable. This change is attributable to a $14.4 million increase in accounts payable related to the construction of our Regency Intrastate Enhancement Project. Since June 30, 2005, we have financed the project with long-term debt and an equity contribution. The decrease is offset by the payment in February 2005 of a post-closing adjustment payment to the former owners in the amount of $5.8 million.

•  a $19.9 million decrease in the value of our current risk management net assets. As a result of increases in NGL prices, the market value of these contracts has resulted in a liability which, if prices remained unchanged, would be paid over the course of the next twelve months.

•  these amounts were offset by a $10.8 million increase in cash, due to the additional borrowings of $60 million and an equity contribution of $15 million by the HMTF Investors to finance the construction of the Regency Intrastate Enhancement Project and repay revolver debt associated with that project.

      We expect to move to a positive working capital position during the first quarter of 2006, following the completion of the Regency Intrastate Enhancement Project and the payment of the associated construction expenditures. With respect to the net risk management liabilities, our cash flows from the sale of products at their market prices will allow us to satisfy these obligations should they materialize.

      Restricted Cash. We have included $6.1 million of restricted cash in other assets, net. This amount of cash was restricted under a covenant in our credit facilities limiting the use of proceeds of certain borrowings thereunder to fund construction of the Regency Intrastate Enhancement Project. The funds were spent on the project in October 2005.

      Cash Flows from Operations. Our cash flows from operations for the eleven months ended November 30, 2004 increased by $25.9 million or 399% from the seven-month period from our date of commencement of operations (June 2, 2003) through December 31, 2003. For the nine months ended September 30, 2005, our cash flows from operations decreased by $8.1 million or 28% from the nine months ended September 30, 2004.

      The increase in the operating cash flows during the eleven-month period ended November 30, 2004 as compared to the seven months ended December 31, 2003 resulted primarily from the increased volumes attributable to the acquisition of our west Texas assets in March 2004. In addition, we commenced active operations in June 2003 and, as a result, 2003 included only seven months of operations while the 2004 period included eleven months of operations. For the eleven months ended November 30, 2004, the west Texas operations contributed the following increases over the seven months ended December 31, 2003: total revenue of $104.6 million, cost of gas and liquids and other cost of sales in the amount of $82.5 million and segment margin of $22.1 million. During the eleven-month period ended November 30, 2004, higher natural gas prices also contributed to improved operating cash flow.

      Net cash provided by operating activities was $21.4 million for the nine months ended September 30, 2005 compared with $29.5 million for the nine months ended September 30, 2004. The decrease was largely due to the following:

•  an increase in cash interest paid of $8.1 million, as the amount of debt financing for the operations of similar scale significantly increased following the HMTF Transaction,

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•  this increase was partially offset by cash flows from the additional two months of operations in the 2005 period of the west Texas assets and other working capital changes.

      For further information regarding our risk management portfolio, please read “— Quantitative and Qualitative Disclosures About Market Risk.”

      For all periods, we used our cash flows from operating activities together with borrowings under our revolving credit facility for our working capital requirements, which include operating expenses, maintenance capital expenditures and repayment of working capital borrowings. From time to time during each period, the timing of receipts and disbursements required us to borrow under our revolving lines of credit. The maximum amounts of revolving line of credit borrowings outstanding during the eleven months ended November 30, 2004 and during the nine months ended September 30, 2005 were $15.0 million and $10.0 million, respectively.

      Cash Flows Used in Investing Activities. Our cash flows used in investing activities for the eleven months ended November 30, 2004 decreased by $38.4 million or approximately 31% over the seven-month period ended December 31, 2003. For the nine months ended September 30, 2005, our cash flows used in investing activities increased by $0.1 million over the comparable period in 2004.

      Our investing cash flows in 2003 were $123.2 million, consisting of $119.5 million invested in our mid-continent and north Louisiana assets in the acquisition from El Paso Field Services LP and affiliates and $3.6 million in capital expenditures.

      Our investing cash flows in the nine months ended September 30, 2004 were $81.2 million, consisting of our investment in our west Texas assets of $67.3 million, our investment in the processing and treating assets acquired from Cardinal for $3.5 million, a $1.2 million distribution from an escrow account relating to the El Paso acquisition, and $11.5 million in capital expenditures.

      Items comprising our investing activities during the eleven-month period ended November 30, 2004 include:

•  $67.3 million invested in our west Texas assets acquired from Duke Energy Field Services in March 2004;

•  $3.5 million invested in gas processing assets acquired from Cardinal on April 1, 2004;

•  $15.1 million invested in capital expenditures partially offset by;

•  $1.2 million received in connection with a distribution from an escrow account relating to the El Paso acquisition.

      For the one month ended December 31, 2004 cash flows used in investing activities were $129.9 million, consisting of $127.8 million of cash payments in connection with the acquisition of Regency Gas LLC by the HMTF Investors on December 1, 2004 and $2.1 million invested in capital expenditures.

      Our cash flows used in investing activities for the nine months ended September 30, 2005 were $81.3 million, consisting of:

•  $76.5 million invested in capital expenditures relating to our Regency Intrastate Enhancement Project and maintenance capital expenditures;

•  $5.8 million invested in acquisition expenses that were paid in February 2005 relating to the acquisition of Regency Gas Services LLC by the HMTF Investors partially offset by;

•  $6.0 million of proceeds from the sale of Cardinal assets.

•  a $6.1 million increase in restricted cash related to the Regency Intrastate Enhancement Project.

      Cash Flows Provided by Financing Activities. Our cash flows used in financing activities for the eleven months ended November 30, 2004 decreased by $61.9 million or approximately 52% from the

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seven-month period ended December 31, 2003. For the nine months ended September 30, 2005, our cash flows provided in financing activities increased by $16.9 million or approximately 31% over the comparable period in 2004.

      Our financing cash flows in 2003 were $118.2 million, consisting of $53.8 million of net increases in member equity investments and $70.0 million in proceeds of borrowings under our credit agreement, all of which were used to finance the acquisition of our mid-continent and north Louisiana assets. These amounts were offset by principal repayments of $3.4 million and the payment of debt issuance costs in the amount of $2.0 million.

      Our financing cash flows during the eleven months ended November 30, 2004 were $56.4 million, consisting of:

•  $10.0 million in proceeds from member equity investments to finance our investment in our west Texas assets;

•  $45.4 million in proceeds from borrowings under our credit agreement, also to finance our investment in our west Texas assets;

•  $10.5 million of repayments under our credit facilities;

•  $13.0 million of borrowings under our revolving credit facility to finance our investment in our west Texas assets; and

•  payment of $1.5 million for debt issuance costs associated with the establishment of credit facilities.

      For the one-month period ended December 31, 2004, our financing cash flows consisted of:

•  $250.0 million in proceeds of borrowings under our credit agreement which was established for our acquisition by the HMTF Investors;

•  $114.5 million of repayments of principal under credit agreements terminated as part of the acquisition by the HMTF Investors;

•  payment of $7.5 million for debt issuance costs associated with the establishment of our credit facilities; and

•  $4.5 million in proceeds from member equity investments to finance a portion of our purchase of crude oil puts.

      Our financing cash flows for the nine months ended September 30, 2004 were $53.9 million, consisting of $10.0 million in proceeds from member equity investments and $45.4 million in proceeds of borrowings under our term loan credit agreement, all to finance our investment in our west Texas assets. In addition, we borrowed $26.0 million under our revolving credit facility and made $20.0 million of repayments during the period. Of the $26.0 million of borrowings so repaid, $10.0 million was used as bridge financing for the west Texas assets and $5.0 million was used to meet working capital needs. We also made $5.9 million in debt repayments under our term loan credit facility and $1.5 million in payments of debt issuance costs.

      In comparison, our net financing cash flows for the nine months ended September 30, 2005 were $70.8 million, consisting of:

•  $60.0 million in proceeds of borrowings under the facility;

•  $15.0 million in equity contributions from the HMTF Investors;

•  $33.0 million in proceeds and repayments of borrowings under our revolving credit facility; and

•  $1.7 million in scheduled repayments of borrowings under our term loan credit facility.

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Capital Requirements

      The midstream energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:

•  Growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; or

•  Maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and extend their useful lives or to maintain existing system volumes and related cash flows.

      We have budgeted $150.2 million in capital expenditures for the year ending December 31, 2005, of which $144.0 million represents growth capital expenditures and $6.2 million represents maintenance capital expenditures. During the first nine months of 2005, our growth capital expenditures were $84.7 million and our maintenance capital expenditures were $4.7 million, including non-cash expenditures in accounts payable. The major portion of the growth capital expenditures budgeted for 2005 was dedicated to our Regency Intrastate Enhancement Project.

      Since our inception in 2003, we have made substantial growth capital expenditures, including those relating to the acquisition of our north Louisiana assets and mid-continent assets in 2003, our west Texas assets in 2004, and the construction of the Regency Intrastate Enhancement Project in 2005. We anticipate that we will continue to make significant growth capital expenditures. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

      Our 2006 forecast includes $22.6 million of identified organic growth capital expenditures. These expenditures relate to several projects, including a dewpoint control conditioning facility in our north Louisiana region, a gathering system development project in our mid-continent region, an acid gas reinjection well at the Waha gas processing plant and the remaining expenditures on our Regency Intrastate Enhancement Project. We expect that these growth capital expenditures will be funded by borrowings under our credit facility.

      We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we will distribute most of our available cash to our unitholders, we will depend on borrowings under our credit facility and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions.

      In January 2005, we initiated the planning, design, implementation and construction of our Regency Intrastate Enhancement Project. In July 2005, we amended and restated our credit facilities, increasing the available term loans to $309 million from $249 million, increasing the available revolving credit to $150 million from $40 million and increasing the available credit for the issuance of letters of credit (which reduces available revolving credit) to $30 million from $20 million. We also negotiated for, and received, an increase in the capital spending covenant that allowed us to construct the project. The term loans originally consisted of $260 million of first lien debt and $50 million of second lien debt.

      Prior to consummation of the additional financing, we repaid the $10 million in outstanding revolving credit loans and at the consummation we borrowed an additional $25 million in term loans, increasing the outstanding borrowings under our credit facilities to $274 million. We subsequently borrowed $35.0 million on September 26, 2005 to meet capital expenditure requirements associated with the Regency Intrastate Enhancement Project.

      On November 30, 2005, we amended our credit facilities further to consolidate our secured indebtedness under a single credit facility and to permit the reorganization and operation of our company as a master limited partnership.

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     Second Amended and Restated Credit Agreement

      On November 30, 2005, Regency Gas Services LLC, or RGS, our wholly owned subsidiary and operating partnership, amended and restated its $410.0 million first lien credit agreement in order to increase the facility to $470.0 million and to increase the availability for letters of credit to $50.0 million. In addition, RGS has the option to increase the term loan commitments under the facility on up to four separate occasions, provided that each such increase must be at least $5.0 million, all such increases must not exceed $40.0 million in the aggregate, no default or event of default shall have occurred or would result due to such increase, and all other additional conditions for the increase of term loan commitments set forth in the facility have been met.

      As of November 30, 2005, the facility consisted of $258.4 million of outstanding term loans, $50.0 million of term loan commitments and $160.0 million of revolving loan commitments. RGS’ obligations under the facility are secured by substantially all of our assets. The revolving loans under the facility will mature on December 1, 2009, and the term loans thereunder will mature on June 1, 2010.

      Interest on borrowings under the second amended and restated credit facility will be calculated, at the option of RGS, at either (a) a base rate plus an applicable margin of 1.25% per annum or (b) an adjusted LIBOR rate plus an applicable margin of 2.25% per annum. RGS shall pay (i) a commitment fee equal to 0.50% per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 2.25% per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

      In addition, RGS amended and restated its $50.0 million second lien credit agreement on November 30, 2005; however, such second lien credit facility was repaid in full through a draw down of the $50.0 million of term loan commitments under the facility described above and terminated on December 2, 2005.

     Third Amended and Restated Credit Agreement

      Upon the consummation of this offering, the second amended and restated credit facility will be amended and restated automatically, and the third amended and restated credit facility will become effective. The revolving loan commitments, the ability to increase its term loan commitments, and the maturity dates under the third amended and restated credit facility will be the same as they are under the second amended and restated credit facility and RGS’ obligations will be secured by substantially all of our assets.

      The Third Amended and Restated Credit Facility contains financial covenants requiring us to maintain debt to EBITDA and EBITDA to interest expense within certain threshold ratios.

      The Third Amended and Restated Credit Facility restricts RGS’ ability to pay dividends, but it authorizes RGS to reimburse us for expenses, and to pay dividends to us, pursuant to our Amended and Restated Agreement of Limited Partnership (so long as no default or event of default has occurred or is continuing). The Third Amended and Restated Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, RGS’ ability (but not our ability) to:

•  incur indebtedness;

•  grant liens;

•  enter into sale and leaseback transactions;

•  make certain investments, loans and advances;

•  dissolve or enter into a merger or consolidation;

•  enter into asset sales or make acquisitions;

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•  enter into transactions with affiliates;

•  prepay other indebtedness or amend organizational documents or transaction documents (as defined in the third amended and restated credit facility);

•  issue capital stock or create subsidiaries; or

•  engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the third amended and restated credit facility or reasonable extensions thereof.

      At September 30, 2005, we had outstanding letters of credit totaling $18.1 million related to our risk management activities. The fees for letters of credit total to a combined annual rate of 2.88%, which is applied to the daily amount of letters of credit exposure. As of January 6, 2006, outstanding letters of credit related to our risk management activities were $10.7 million.

      Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations.

      Credit Ratings and Debt Covenants. The current credit ratings on our debt under our credit facility are B1 with a negative outlook by Moody’s Investor Service and B+ with a stable outlook by Standard and Poor’s. At September 30, 2005, we were in compliance with the covenants of the credit facilities. See Note 3 to the accompanying financial statements for additional information on the credit facilities.

      Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of September 30, 2005. Of the $308.4 million of term loans outstanding on September 30, 2005, $258.4 million is scheduled for interest rate resets on three-month intervals, with the remaining $50 million on 30 day reset intervals. Interest rates were reset for all amounts outstanding on September 30, 2005.

	Payments Due by Period
Contractual Obligations	Total		2005		2006		2007		2008-2009		Thereafter
	($ Millions)
Long-Term Debt (including interest)(1)	$	421.7	$	6.5	$	25.9	$	26.7	$	53.0		$309.6
Operating Leases		1.2		0.1		0.4		0.4		0.3		—
Purchase Obligations(2)(3)		31.6		31.6		—		—		—		—
Total Contractual Obligations(4)	$	454.5	$	38.2	$	26.3	$	27.1	$	53.3		$309.6

(1)	Assumes a current LIBOR interest rate of 4.28% plus the applicable margin, which remains constant in all periods. The calculation excludes the savings associated with the November 30, 2005 amendment of our credit facilities.
(2)	Represents the purchase obligation for the 80-mile, 30-inch diameter pipeline extension on our Regency Intrastate Pipeline system.
(3)	Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.
(4)	These amounts do not include the $2.3 million and $1.2 million that we expect to spend in 2006 and 2007, respectively, for the construction of an acid gas reinjection well at our Waha gas processing plant.

      The table above does not include our existing obligations under our ten-year financial advisory and monitoring and oversight agreements between us and an affiliate of Hicks Muse to pay certain management fees and transaction advisory fees to the affiliate of Hicks Muse. We have agreed to pay $9.0 million of the proceeds from this offering to the affiliate of Hicks Muse to terminate these agreements. As a result, we will not have any continuing obligation to make payments under these agreements following this offering.

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Recent Accounting Pronouncements

      On October 6, 2005, the FASB issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings that are incurred during a construction period. We considered how this might apply to our payment for rights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of the recently issued Staff Position FAS 13-1.

      In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This accounting standard is effective for fiscal years beginning after December 15, 2005. We do not believe this accounting standard will have a material adverse effect on our results of operations or financial condition.

Quantitative and Qualitative Disclosures About Market Risk

     Risk and Accounting Policies

      We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Our management has established comprehensive risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of our general partner is responsible for the overall approval of market risk management policies. The Risk Management Committee is composed of directors (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

      See “— Critical Accounting Policies and Estimates — Risk Management Activities” for further discussion of the accounting for derivative contracts.

     Commodity Price Risk

      We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and other commodities as a result of our gathering, processing and marketing activities, which produce a naturally long position in both natural gas and NGLs. We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities. To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial hedges to mitigate the risk. It is our policy not to take any speculative marketing positions.

      In some cases, we may not be able to match pricing terms or to cover our risk to price exposure with financial hedges and may be exposed to commodity price risk. For example, under many of our contracts in place in west Texas, we are obligated to purchase gas at a published first of the month, or FOM, index price. We then sell the gas at the same index price. In November 2005, in a highly unusual circumstance, there were very few baseload FOM index sales reported and we were unable to find buyers at these prices. The ensuing daily cash price was substantially less than the posted FOM index. We were able to convince substantially all the producers of this natural gas that the index price was an anomaly and that the purchase price and the sale price should be matched. In order to prevent this from occurring again, we are in the process of amending these contracts to provide for a closer matching of the pricing of purchases and sales in such circumstances.

      Both our profitability and our cash flow are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow

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from reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Our overall direct exposure to movements in natural gas prices is minimal as a result of natural hedges inherent in our contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our service. We are a net seller of NGLs, and as such our financial results are exposed to fluctuations in NGLs pricing. We have executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options. As a result, we have hedged approximately 95% of our expected exposure to NGL prices in 2006, and approximately 75% in 2007. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

      The following table sets forth certain information regarding our NGL swaps, valued as of September 30, 2005:

Notional

Volume

We Receive

Fair Value

Period

Commodity

(MBbls)

We Pay

($/gallon)

(Thousands)

Oct. 2005 - Dec 2007

Ethane

1,073

Index

$0.49 to $0.58

$

(8,944

)

Oct. 2005 - Dec 2007

Propane

930

Index

$0.66 to $0.825

(13,762

)

Oct. 2005 - Dec 2007

Butane

498

Index

$0.83 to $1.085

(5,136

)

Jan. 2006 - Dec 2007

Natural Gasoline

164

Index

$1.22 to $1.26

(1,333

)

Total Fair Value

$

(29,175

)

      The following table sets forth certain information regarding our crude oil puts:

		Notional
		Volume		Strike Prices		Fair Value
Period	Commodity	(MBbls)		($/Bbl)		(Thousands)
October 2005 - December 2007	NYMEX West Texas Intermediate Crude		2,575	$	30 to $42	$	919

      The table below summarizes the changes in commodity and interest rate risk management assets and liabilities for the nine months ended September 30, 2005.

	$ in millions
Net Risk Management Asset at December 31, 2004	$	9.0
Settlements of positions included in beginning balance		2.7
Unrealized mark-to-market valuations of positions held at June 30, 2005		(15.3	)
Other*		(0.7	)
Balance of Risk Management Assets (Liability) at June 30, 2005		(4.3	)
Settlements of positions included in June 30, 2005 balance		3.5
Unrealized mark-to-market valuations of positions held at September 30, 2005		0.3
Effective portion of hedges included within Other Comprehensive Income		(25.7	)
Other*		(0.6	)
Balance of Net Risk Management Liability at September 30, 2005	$	(26.8	)

*  The amounts reported as “other” represents the expiration of options for which premiums were paid in prior periods.

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     Credit Risk

      Our purchase and resale of natural gas exposes us to credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore a credit loss can be very large relative to our overall profitability. We are diligent in attempting to ensure that we issue credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or parental guarantees.

      In January 2005, one of our customers filed for Chapter 11 reorganization under U.S. bankruptcy law. The customer operates a merchant power plant, for which we provide firm transportation of natural gas. Under the contract with the customer, the customer is obligated to make fixed payments in the amount of approximately $3.2 million per year. The contract expires in mid-2012 and was secured by a $10.0 million letter of credit. In December 2005, in connection with other contract negotiations, the letter of credit was reduced to $3.3 million. The customer has accepted the firm transportation contract in bankruptcy. The customer’s plan of reorganization has been confirmed by the bankruptcy court and the customer has since emerged from bankruptcy protection. At the date of this prospectus, the customer was current in its payment obligations.

     Interest Rate Risk

      The credit markets recently have experienced 50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

      We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To minimize this risk, we entered into an interest rate swap in January 2005 for $125 million of the initial $250 million of term loans at 6.47% for a period of two years. When we amended and restated our credit facility in July 2005, we entered into two additional interest rate swaps. The first has a notional amount of $75.0 million, bringing the total notional amount to $200 million with a March 2007 maturity. As a result, we have converted $200 million of $309 million of term loans, or approximately two-thirds, of our variable interest rate debt to fixed interest rate debt from August 2005 through March 2007 at a fixed rate of 6.70%. The second interest rate swap has a notional amount of $200.0 million that is effective from April 2007 through March 2009, and effectively fixes our interest rate at 7.36% on this amount for two years. Our variable interest rate debt bears interest at variable rates based on LIBOR or the bank’s prime rate. The fair value of our interest rate swaps as of September 30, 2005 was $1.4 million.

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BUSINESS

Overview

      We are a Delaware limited partnership recently formed by Hicks Muse to capitalize on opportunities in the midstream sector of the natural gas industry. We are a growth-oriented independent midstream energy partnership engaged in the gathering, processing, marketing and transportation of natural gas. We provide these services through systems located in north Louisiana, west Texas and the mid-continent region of the United States, which includes Kansas, Oklahoma, Colorado and the Texas Panhandle.

      We divide our operations into two business segments:

•  Gathering and Processing: provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate the NGLs, and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

•  Transportation: delivers transports natural gas from northwest Louisiana to north central Louisiana through our 280-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project.

     Gathering and Processing Segment

      We operate our Gathering and Processing segment in three geographic areas of the United States: north Louisiana, west Texas and the mid-continent region. Our gathering and processing assets include five cryogenic processing plants, of which four are currently active, and approximately 2,950 miles of related gathering and pipeline infrastructure connected to approximately 2,650 active wells. In north Louisiana, we own a large gathering system that is connected to two processing plants that we own and operate. In west Texas, we own a large gathering system that is connected to a processing plant that we own and operate. In the mid-continent region, we own three large gathering systems, one of which is connected to a processing plant that we own and operate. Our Gathering and Processing segment also includes our NGL marketing business through which we sell the NGLs that are produced by our processing plants for our own account and for the accounts of our customers.

      The following table contains information regarding our gathering systems and processing plants as of September 30, 2005:

									Throughput
			Length		Wells		Compression		Capacity
Region	Asset Type		(Miles)		Connected		(Horsepower)		(MMcf/d)
North Louisiana		Gathering pipelines		600		700		14,500		300
		Processing facilities		—		—		10,000		90
West Texas		Gathering pipelines		750		450		22,000		200
		Processing facility		—		—		20,000		125
Mid-Continent		Gathering pipelines		1,600		1,500		41,500		265
		Processing facility		—		—		3,650		50	(1)

(1)  Excludes 80 MMcf/d of throughput capacity available at our inactive Lakin processing facility.

     Transportation Segment

      Our Transportation segment consists of our Regency Intrastate Pipeline system, a 280-mile natural gas pipeline in north Louisiana that transports natural gas primarily from northwest Louisiana to north central Louisiana where it connects to a number of interstate and intrastate pipelines. As of September 30, 2005, the Regency Intrastate Pipeline system had a capacity of 250 MMcf/d with 17,900 horsepower of

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compression and a 35 MMcf/d refrigeration plant for hydrocarbon dewpoint control. During the nine months ended September 30, 2005, the system had average throughput of 232 MMcf/d.

      Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result, we have completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. The project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.

      The Regency Intrastate Enhancement Project is a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to access new sources of supply and markets. We began planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005.

      The total cost of this project is expected to be approximately $140 million, which includes the expansion of our existing Regency Intrastate Pipeline system and an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system supported by approximately 9,500 horsepower of additional compression. The project has extended our transportation services into additional major producing fields in north Louisiana and has connected our system to additional interstate and intrastate pipelines in northeast Louisiana.

      The completion of the Regency Intrastate Enhancement Project, enables us to provide transportation services from the three largest natural gas producing fields in Louisiana. Prior to the completion of the final phase of the project in December 2005, we were transporting approximately 265 MMcf/d under existing contracts, including 65 MMcf/d attributable to the completion of the first two phases of the project. Additionally we have signed definitive agreements for 249 MMcf/d of firm transportation and 156 MMcf/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining incremental transportation capacity of 130 MMcf/d resulting from the Regency Intrastate Enhancement Project.

Business Strategies

      Our management team is dedicated to increasing the amount of cash available for distribution to each outstanding unit. We intend to achieve this by pursuing organic growth projects that yield attractive returns and by capitalizing on accretive acquisition opportunities.

      Our specific strategies include:

•  Implementing cost-effective organic growth opportunities. We intend to build natural gas gathering assets, processing facilities and transportation lines that enhance our existing systems and our ability to aggregate supply and to access premium markets for that supply. We will emphasize projects that increase volume throughput and are expected to generate attractive returns, such as our Regency Intrastate Enhancement Project and our project to provide gathering facilities for a long-term exploration and development program under an existing letter of intent with a producer in the Mid-Continent area. We are also evaluating, but have not yet made any decision to pursue, other organic growth projects. The projects under consideration include:

•  Expansion of our Regency Intrastate Pipeline west of Haughton to relieve capacity constraints and extensions of the pipeline laterally into other fields beyond Winnsboro;

•  construction and installation of a refrigeration plant at Longwood or Sibley or both;

•  construction of additional compression at Mainline;

•  construction of a storage facility in proximity to the Regency Intrastate Pipeline in conjunction with a third party; and

•  initiation and construction of step out expansion projects for our Waha gathering system.

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•  Continuing to enhance profitability of our existing assets. We intend to increase the profitability of our existing asset base by identifying new business opportunities, adding new volumes of natural gas supplies, undertaking additional initiatives to enhance utilization and continuing to reduce costs. As an example, until recently, the NGLs produced by our processing plants were sold to third parties as mixed NGLs. In September 2005, we began delivering the mixed NGLs produced by our processing plants to operators of fractionation facilities for fractionation for our account. We then sell the individual components, such as ethane, propane and isobutane, directly to marketing companies, refineries and other wholesalers. We believe this marketing function will allow us to earn additional margins from the sale of the NGLs that otherwise would have been earned by the fractionator.

•  Pursuing accretive acquisitions of complementary assets. We intend to pursue strategic acquisitions of midstream assets in or near our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of those assets. We also intend to pursue opportunities in new regions with significant natural gas reserves and high levels of drilling activity. We believe that there will be additional acquisition opportunities as a result of the ongoing divestiture of midstream assets by large industry participants.

•  Continuing to reduce our exposure to commodity price risk. Because of the volatility of natural gas and NGL prices, we attempt to operate our business in a manner that allows us to mitigate the impact of fluctuations in commodity prices and to generate stable cash flows. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. We have reduced and intend to continue to reduce, when the opportunity arises, our commodity price exposure by replacing keep-whole contracts with fee based or percentage-of-proceeds gas processing contracts. We have executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options. (Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil.) As a result, we have hedged approximately 95% of our expected exposure to NGL prices in 2006, and approximately 75% in 2007. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

•  Improving our credit ratings. We are committed to achieving an investment grade rating on our debt. The current credit ratings on our debt under our credit facilities are B+ by Standard & Poor’s and B1 by Moody’s. The additional revenue and cash flow resulting from the completed Regency Intrastate Enhancement Project will significantly improve our credit statistics that are considered by the rating agencies. We will consider the impact such opportunities will have on our credit ratings and financial flexibility.

      We intend to finance our growth projects through a combination of funds available under our credit facility, commercial bank borrowings and the issuance of debt and equity securities. Given our policy of distributing available cash, we may not be able to finance such growth through the application of internal cash flow. Please read the risk factor “Because we distribute substantially all our cash available for distribution to our unitholders, our future growth may be limited” under “Risk Factors — Risks Relating to Our Business” for details regarding the risks of this growth strategy.

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Competitive Strengths

      We believe that we are well positioned to execute our strategies and to compete in the natural gas gathering, processing, marketing and transportation businesses based on the following competitive strengths:

•  We have a significant market presence in major natural gas supply areas. We have a significant market presence in each of our operating areas, which are located in some of the largest and most prolific gas-producing regions of the United States: the Louisiana-Mississippi-Alabama Salt basin in north Louisiana, the Delaware and Devonian basins of west Texas and the Hugoton and Anadarko basins in the mid-continent area. Our geographical diversity reduces our reliance on any particular region, basin or gathering system. Each of these producing regions is well-established with generally long-lived, predictable reserves, and our assets are strategically located in each of the regions. Currently, these areas are experiencing increased levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

•  Our recently completed Regency Intrastate Enhancement Project will provide us with the opportunity to increase significantly our fee-based transportation throughput and cash flow. Prior to the completion of the Regency Intrastate Enhancement Project, a portion of the Regency Intrastate Pipeline system was at full capacity and was not able to capitalize on the current significant constraint on the flow of natural gas from prolific producing fields in north Louisiana to intrastate and interstate markets in east Louisiana. As a result of this bottleneck in the pipeline, we had not been able to increase significantly the throughput on the pipeline despite an increase in drilling and production in the area. Our Regency Intrastate Enhancement Project has substantially increased the pipeline’s capacity by alleviating the bottleneck and extending the pipeline to additional intrastate and interstate markets in east Louisiana. We expect this expansion project will provide us with significant additional transportation throughput volumes and stable, fee-based cash flow.

•  We have the financial flexibility to pursue growth opportunities. As part of the recent amendment of our credit facilities, we expanded the available borrowing capacity under our revolving credit facility to $160 million. The expansion of our revolving credit facility provides us with the liquidity and financing flexibility we will need to execute our business strategy. We remain committed to maintaining a balanced capital structure which will afford us the financial flexibility to fund expansion projects and other attractive investment opportunities.

•  We have an experienced, knowledgeable management team with a proven track record of performance. Our management team has a proven track record of enhancing value through the investment in and the acquisition, exploitation and integration of energy assets. Our senior management has an average of over 20 years of industry related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation and focus for managing and enhancing our operations, for accessing strategic acquisition opportunities and for constructing new assets. After giving effect to this offering, members of our senior management team will have a substantial economic interest in us.

•  We are affiliated with Hicks Muse, a leading private equity investment firm headquartered in Dallas, Texas. Our affiliation with Hicks Muse provides us with significant benefits. We expect that our relationship with Hicks Muse will provide us with several significant benefits, including access to a significant pool of operational, transactional and financial professionals, multiple sources of capital and increased exposure to acquisition opportunities. Hicks Muse is a leading private equity firm with total funds managed of over $10 billion. Since the firm’s founding in 1989, Hicks Muse’s experienced investment team has completed more than 400 transactions with a total value in excess of $50 billion.

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Industry Overview

      General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant located near the production, where it is treated and dehydrated and then processed through cryogenic or other processing facilities. Natural gas processing involves the separation of raw natural gas into pipeline-quality natural gas, principally methane, and mixed NGLs. It also entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by interstate and intrastate pipelines to end users. Mixed NGLs that are produced by processing raw natural gas are typically transported via NGL pipelines or by truck to a fractionator, which separates the NGL into its components, such as ethane, propane, normal butane, isobutane and natural gasoline. NGLs are then sold to end users.

      The following diagram depicts our role in the process of gathering, processing, marketing and transporting natural gas.

      Overview of U.S. market. The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-use markets. The midstream natural gas industry in North America includes approximately 574 processing plants that process approximately 47 Bcf of natural gas per day and produce approximately 77 million gallons per day of NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas wells.

      Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.1 trillion cubic feet, or Tcf, in 2004 to approximately 25.4 Tcf in 2010, representing an annual growth rate of over 2.3%. During the five years ending December 31, 2004, the United States has on average consumed approximately 22.6 Tcf per year, while total marketed domestic production averaged approximately 19.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

      Gathering and treating. The process of raw natural gas gathering begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collect natural gas from points near producing wells and transport it to larger pipelines for further transportation. We own and operate five large gathering systems.

      Raw natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Raw natural gas produced in some areas may contain hydrogen sulfide, carbon dioxide, nitrogen and other impurities. Treating plants, such as the one that we own and operate at our

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Waha facility, remove these impurities before the natural gas is introduced to the processing plant. Our Waha facility utilizes an amine treating process, which involves a continuous circulation of a liquid chemical called amine that physically contacts with the raw natural gas. The amine reacts with carbon dioxide and hydrogen sulfide, removing them from the gas stream prior to further processing.

      Compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production in the ground against a higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Field compression is typically used to lower the entry pressure, while maintaining or increasing the exit pressure, of a gathering system to allow it to operate at a lower receipt pressure and provide sufficient pressure to deliver gas into a higher downstream pipeline.

      Processing. Raw natural gas produced at the wellhead is often unsuitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. The principal components of raw natural gas are methane and ethane, but most raw natural gas also contains varying amounts of NGLs (such as ethane, propane, normal butane, isobutane, and natural gasoline) and impurities, such as water, sulfur compounds, carbon dioxide, or nitrogen. Raw natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other impurities removed to very low concentrations. Raw natural gas is processed not only to remove unwanted impurities that would interfere with pipeline transportation or use of raw natural gas, but also to separate from the gas those hydrocarbon liquids that have higher values as NGLs. We own and operate four cryogenic natural gas processing plants. The cryogenic process utilizes heat exchangers and a turbo-expander to cool the gas and condense the NGLs. The NGLs are then separated from the gaseous components.

      Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. We do not own or operate any NGL fractionation facilities. We ship the NGLs that we produce to a fractionator. 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. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutane. Isobutane is fractionated from mixed butane (a stream of butane and isobutane in solution) or refined from normal butane, principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.

      Marketing. Natural gas and NGL marketing involves the sale of the pipeline-quality gas and NGLs that are either produced by processing plants or purchased from gathering systems or other pipelines. Our recently formed marketing function markets NGLs for our account and for the accounts of our customers.

      Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to industrial end-users, utilities and other pipelines. We own and operate an intrastate natural gas pipeline system in north Louisiana. Our intrastate natural gas pipeline system includes a refrigeration processing plant that is utilized to reduce the hydrocarbon dewpoint of natural gas in order to meet downstream market pipeline-quality specifications.

Gathering and Processing Operations

     General

      We contract with producers to gather raw natural gas from individual wells or central delivery points located near our processing plants or gathering systems. Once we have executed a contract, we connect

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wells and central delivery points to our gathering lines through which the raw natural gas is delivered to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At our processing plants, we remove any impurities in the raw natural gas stream and process the gas and extract the NGLs.

      We continuously seek new sources of raw natural gas supply to increase throughput volume on our systems and through our plants. We connected 44 new wells in 2004 and 87 new wells during the first nine months of 2005, including connections of central delivery points which may have multiple wells behind them.

      All raw natural gas flowing through our gathering and processing facilities is supplied under gathering and processing contracts having fixed terms ranging from month-to-month to 20 years. Alternatively, we have some contracts that span the life of the oil and gas lease. For a description of our contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

      The pipeline-quality natural gas remaining after separation of NGLs through processing is either returned to the producer or sold, for our own account or for the account of the producer, at the tailgates of our processing plants for delivery through interstate or intrastate gas transportation pipelines.

      Until recently, the NGLs produced by our processing plants were sold to third parties as mixed NGLs. In September 2005, we began delivering the mixed NGLs produced by our processing plants to operators of fractionation facilities for fractionation for our account. We then sell the individual components, such as ethane, propane and butane, directly to marketing companies, refineries and other wholesalers. We believe this marketing function will allow us to earn additional margins from the sale of the NGLs that otherwise would have been earned by the fractionator.

      Our natural gas gathering and processing assets consist primarily of five large natural gas gathering systems and four active cryogenic gas processing plants which are located in north Louisiana, West Texas and the mid-continent region of the United States. The following table contains certain information regarding these gathering systems and processing plants as of and for the nine months ended September 30, 2005:

								Throughput
		Length		Wells		Compression		Capacity
Asset		(Miles)		Connected		(Horsepower)		(MMcf/d)
North Louisiana
	Dubach/ Calhoun/ Lisbon Gathering System		600		700		14,500		300
	Dubach Processing Plant		—		—		7,000		50
	Lisbon Processing Plant		—		—		3,000		40
West Texas
	Waha Gathering System		750		450		22,000		200
	Waha Processing Plant		—		—		20,000		125
Mid-Continent
	Hugoton Gathering System		850		900		28,000		120
	Mocane-Laverne Gathering System		500		350		4,000		100
	Greenwood Gathering System		250		250		9,500		45
	Mocane Processing Plant		—		—		3,650		50

     North Louisiana System

      Our north Louisiana system includes the Dubach and Lisbon processing plants and the Dubach/ Calhoun/ Lisbon gathering system, which is a large integrated natural gas gathering and processing system located primarily in four parishes of north Louisiana and includes over 600 miles of gathering pipelines.

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      The following is a map of our north Louisiana gathering and processing system.

      This system is located in active drilling areas in north Louisiana. Through our Dubach/ Calhoun/ Lisbon gathering system and its interconnections with our Regency Intrastate Pipeline system in north Louisiana described in “— Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, marketing and transportation.

      Natural Gas Supply. The natural gas supply for our north Louisiana gathering systems is derived primarily from natural gas wells located in the following four parishes in north Louisiana: Claiborne, Union, Lincoln and Ouachita. Our operating areas have experienced significant levels of drilling activity providing us with opportunities to access newly developed natural gas supplies. Natural gas production in this area has increased as a result of the additional drilling, which includes deeper reservoirs in the Cotton Valley and Hosston trends.

      During the nine months ended September 30, 2005, we connected 41 wells to our north Louisiana gathering system.

      Devon Energy Corporation and XTO Energy Inc. represented approximately 20% and 11%, respectively, of our natural gas supply in this region for the year ended December 31, 2004.

      Dubach/ Lisbon/ Calhoun Gathering System. The Dubach/ Lisbon/ Calhoun gathering system consists of over 600 miles of natural gas gathering pipelines ranging in size from two inches in diameter to ten inches in diameter. The system gathers raw natural gas from producers and delivers approximately 85% of the raw natural gas to either the Dubach or Lisbon processing plants for processing. The remainder of the raw natural gas is lean natural gas, which does not require processing and is delivered directly to interstate pipelines and our Regency Intrastate Pipeline system.

      Dubach Processing Plant. The Dubach processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Dubach and Calhoun gathering systems and natural gas transported on the Regency Intrastate Pipeline system. This plant, which was acquired by us as part of the El Paso assets in 2003, was originally constructed in 1980 and was subsequently reassembled in its present location in 1994.

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      Lisbon Processing Plant. The Lisbon processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Lisbon gathering system. This plant, which was acquired by us as part of the El Paso assets, was constructed in 1980 and was subsequently reassembled in its present location in 1996.

      Markets. There are numerous market outlets for the raw natural gas that we gather and the NGLs that we produce on our north Louisiana systems. The Dubach/ Lisbon/ Calhoun gathering system is directly connected to several interstate natural gas pipelines, including Texas Gas Transmission, Mississippi River Transmission and Texas Eastern Transmission, and to our Regency Intrastate Pipeline system. Our access to numerous markets, including interstate pipelines in northeast Louisiana and to several power plants located on our system, provides us with the flexibility to sell our natural gas supply into markets with the most attractive pricing.

      The NGLs extracted from the raw natural gas at our processing plants are transported by a 37-mile Regency NGL pipeline to a third-party pipeline that delivers the NGLs to Mont Belvieu, Texas for fractionation by third parties.

      Our primary purchasers of pipeline-quality gas on the north Louisiana gathering system are Atmos Energy Marketing, LLC, Duke Energy Field Services and AGL Resources Inc., which represented approximately 61%, 15% and 10%, respectively, of the revenues from such sales for the nine months ended September 30, 2005. All of the NGL sales from the north Louisiana processing plants were made to Koch Hydrocarbon, LP, which provided fractionation services during this period.

     West Texas System

      Our west Texas gathering system (Waha) is a large integrated natural gas gathering and processing system in west Texas. The Waha gathering system consists of 750 miles of natural gas gathering pipelines and the Waha processing plant. The system covers four Texas counties surrounding the Waha Hub, one of Texas’ major natural gas market areas. Through our Waha gathering system, we offer producers wellhead to market services. As a result of the proximity of this system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets.

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      The following is a map of our Waha gathering and processing system.

      Natural Gas Supply. The natural gas supply for the Waha gathering system is derived primarily from natural gas wells located in four counties in west Texas near and around the Waha Hub. Natural gas exploration and production drilling in this area has primarily targeted productive zones in the Permian Delaware basin and Devonian basin. These basins are mature basins with wells that generally have long lives and predictable and steady flow rates.

      This area is experiencing increasing levels of oil and natural gas drilling activity as a result of strong demand for natural gas and recent discoveries. In addition, several independent exploration and production companies are pursuing more aggressive drilling programs than the major oil companies that once were the primary producers in the area. Several of these independent exploration and production companies are developing unexploited reserves within our area of operations through new well completions and infill drilling, along with workovers and re-completions of existing wells. Additionally, there have been recent large oil and natural gas discoveries in this region by Chesapeake Energy Corporation and the Anadarko Petroleum Company. We believe that our significant presence and modern and efficient asset base provides us with competitive advantages in capturing new supplies of natural gas in the region. Many of these areas of increased drilling require little to no pipeline or meter expense as producers are connecting to existing facilities.

      During the nine months ended September 30, 2005, we connected to 26 wells to our Waha gathering system.

      Duke Energy Field Services and ExxonMobil Corporation represented approximately 24% and 14%, respectively, of our natural gas supply in this region for the year ended December 31, 2004.

      Waha Gathering System. The Waha gathering system consists of approximately 750 miles of natural gas gathering pipelines ranging in size from three inches in diameter to 24 inches in diameter. We offer producers four different levels of natural gas compression on the Waha gathering system, as compared to the two levels typically offered in the industry. By offering multiple levels of compression, our gathering system is often more cost-effective for our producers, since the producer is not required to pay for a level of compression that is higher than the level it requires.

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      Waha Processing Plant. The Waha processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Waha gathering system. This plant was constructed in 1965, and, due to recent upgrades to state of the art cryogenic processing capabilities, we believe it is a highly efficient raw natural gas processing plant. The Waha processing plant also includes an amine treating facility that has a capacity of approximately 125 MMcf/d. The treating facility uses an amine treating process to remove carbon dioxide and hydrogen sulfide from raw natural gas that is gathered in our Waha gathering system before the natural gas is introduced to the processing plant.

      Markets. The Waha gathering system has a variety of market outlets for the natural gas that we gather and the NGLs that we produce. The pipeline-quality gas from our gathering and processing operations can be delivered into the Waha Hub, which includes connections to several major interstate and intrastate pipelines serving California, the mid-continent and Texas natural gas markets, including Oasis Pipeline, Enterprise Texas Pipeline, Atmos Pipeline, ONEOK Westex and El Paso Natural Gas Pipeline. The NGLs extracted from the raw natural gas at the Waha processing plant are transported to ExxonMobil’s NGL pipeline, which delivers the NGLs to facilities in Mont Belvieu, Texas for fractionation by third parties.

      Our primary purchasers of pipeline-quality gas on the west Texas gathering system are Energy Transfer Partners, Tenaska Marketing Ventures, and ONEOK Energy Marketing and Trading, L.P., which represented approximately 45%, 26% and 8%, respectively, of the revenues from such sales for the nine months ended September 30, 2005. All of the NGL sales from the Waha processing plant were made to ExxonMobil Corporation, which fractionated the NGLs from these plants during this period.

     Mid-Continent Systems

      Our mid-continent systems include the following natural gas gathering systems primarily in Kansas and Oklahoma:

•  the Hugoton gathering system, which is a large integrated natural gas gathering and processing system located in southwestern Kansas and includes approximately 850 miles of gathering pipeline;

•  the Mocane-Laverne gathering system, which is a large integrated natural gas gathering and processing system located primarily in the Oklahoma Panhandle and includes approximately 500 miles of gathering pipelines and the Mocane cryogenic processing plant; and

•  the Greenwood gathering system, which is a large natural gas gathering system located primarily in southwestern Kansas and includes approximately 250 miles of gathering pipelines.

      Our mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas from approximately 1,500 wells. These systems are geographically concentrated, with each central facility located within 90 miles of the others. We operate our mid-continent gathering systems at low pressures to increase the total throughput from the connected wells. Wellhead pressures are therefore adequate to access the gathering lines without the cost of wellhead compression. In addition, we process natural gas from the Mocane-Laverne gathering system at our Mocane processing plant.

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      The following is a map of our mid-continent gathering and processing systems.

      Natural Gas Supply. Our mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, including the Hugoton Basin in southwest Kansas and the Anadarko Basin in western Oklahoma and the Texas panhandle. These mature basins have continued to provide generally long-lived, predictable reserves. Recent increases in production in these areas have been driven primarily by continued infill drilling, compression enhancements, and advanced wellbore completion technology. In addition, the application of 3-D seismic technology in these areas has yielded better-defined reservoirs for continuing development of these basins.

      During the nine months ended September 30, 2005, we connected 20 wells to our mid-continent gathering systems.

      Occidental Petroleum Corporation, Cimarex Energy Co. and Penn Virginia Corporation provided approximately 22%, 11% and 10%, respectively, of our natural gas supply in this region for the year ended December 31, 2004.

      Hugoton Gathering System. The Hugoton gathering system is located in southwestern Kansas. It consists of approximately 850 miles of natural gas gathering pipelines ranging in size from two inches in diameter to 20 inches in diameter. Substantially all of the raw natural gas gathered by the Hugoton gathering system is delivered to a third party’s processing plant. We pay the third party a fee to process the gas for our account.

      Mocane-Laverne Gathering System. The Mocane-Laverne gathering system is located in Beaver and Harper counties in the Oklahoma panhandle and Meade County in southwestern Kansas. It consists of approximately 500 miles of natural gas gathering pipelines ranging in size from two inches in diameter to 24 inches in diameter. The system gathers raw natural gas from producers and delivers it for processing to the Mocane processing plant.

      Mocane Processing Plant. The Mocane processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Mocane-Laverne gathering system. This plant was constructed in 1975 and acquired by us as part of the El Paso assets in 2003.

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      Greenwood Gathering System. The Greenwood gathering system is located in Morton and Stanton Counties in southwestern Kansas and Baca County in southeastern Colorado. It consists of approximately 250 miles of natural gas gathering pipelines ranging in size from four inches in diameter to 20 inches in diameter. The raw natural gas gathered by this system is delivered to a third party’s processing plant. We pay the third party a fee to process the gas for our account.

      Markets. The pipeline-quality gas from our gathering and processing operations in the mid-continent area is delivered primarily into Panhandle Eastern Pipeline to serve markets in the mid-continent and upper Midwest. This gas can also be sold into the ANR Pipeline via the North Kiowa system or via the CIG Pipeline or can be pooled through BP’s Jayhawk processing plant and Pioneer Natural Resources’ Santanta processing plant.

      The NGLs extracted from the raw natural gas at our gathering and processing plants are transported by a third party NGL pipeline that delivers the NGLs to the Conway Hub in Kansas for fractionation by third parties.

      Our primary purchasers of pipeline-quality gas on the mid-continent gathering system are BP Energy Company, Seminole Energy Services, LLC, and Cinergy Marketing and Trading, LP, which represented 40%, 36% and 18%, respectively, of the revenues from such sales for the nine months ended September 30, 2005. All of the NGL sales from the mid-continent processing plants were made to Koch Hydrocarbon, LP, which fractionated these NGLs during this period.

     Other Processing Systems

      We also own the Lakin processing plant, which is a cryogenic processing plant with nitrogen rejection and helium recovery capabilities. This plant has a capacity of 80,000 Mcf/d. The plant was constructed in 1995 and was acquired by us as part of the El Paso assets in 2003. Through July 31, 2005, the Lakin processing plant processed raw natural gas received from the Hugoton gathering system. As part of our previously planned strategy, we suspended operations at the Lakin processing plant (subject to intermittent resumption) as of August 1, 2005. Suspending the operations of the plant allowed us to renegotiate certain unfavorable keep-whole processing contracts covering gas processed at the plant and replace them with fee-based contracts and to avoid charges for transporting natural gas from the Hugoton gathering system through a third party pipeline out of the tailgate of the Lakin plant. All of the gas from the Hugoton gathering system is now processed at a third party processing plant for our account for a fee. We are currently evaluating opportunities to utilize the Lakin processing plant, which may include connecting new source of supply to the plant or moving the plant to another area.

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Transportation Operations

      General. We own and operate a 280-mile intrastate natural gas pipeline system, known as the Regency Intrastate Pipeline system, in north Louisiana extending from northwest Louisiana to north central Louisiana. This system includes 17,900 horsepower of compression and a 35 MMcf/d refrigeration plant for hydrocarbon dewpoint control. The following map presents the location of the Regency Intrastate Pipeline system, including the Regency Intrastate Enhancement Project described below:

      The following table contains certain information regarding the Regency Intrastate Pipeline system prior to the commencement of construction and following the completion of the Regency Intrastate Enhancement Project:

						Throughput
		Length		Compression		Capacity		Market
Asset		(Miles)		(Horsepower)		(MMcf/d)		Outlets
Regency Intrastate Pipeline System
	Pre-Enhancement Project		200		17,900		200		6
	Post-Enhancement Project		280		27,400		800		11
Haughton Refrigeration Processing Plant			—		—		35		—

      As of September 30, 2005, the Regency Intrastate Pipeline system had a capacity of 250 MMcf/d. During the year ended December 31, 2004 and the nine months ended September 30, 2005, the Regency Intrastate Pipeline system had average throughput of 177 MMcf/d and 232 MMcf/d, respectively.

      Natural gas generally flows from west to east on the pipeline from wellhead connections or connections with other gathering systems. Prior to the completion of our Regency Intrastate Enhancement Project, our Regency Intrastate Pipeline system consisted of the following components:

•  the Elm Grove System;

•  the North Louisiana Pipeline;

•  the Metco Pipeline;

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•  the Ruston System;

•  the Panda Pipeline; and

•  the Dubach Extension.

      The Elm Grove System is a 31-mile, 12-inch diameter pipeline that extends from Southwestern Electric Power Company’s Arsenal Hill Power Plant in Caddo Parrish eastward to the Elm Grove natural gas field in Bossier Parish. The Elm Grove system has several active receipt and delivery points. The pipeline was constructed and put into operation in 1974.

      The North Louisiana Pipeline is comprised of a 23-mile, 12-inch diameter pipeline and a 25-mile, 16-inch diameter pipeline that extends from the tie-in point with the Elm Grove System to an interconnection with a pipeline owned by Southern Natural Gas Company in Bienville Parish. Along the line there are currently interconnections with an intrastate pipeline and a gathering system owned by Duke Energy Field Services and pipelines owned by El Paso, Southern Natural Gas Co. and Texas Eastern Transmission, L.P. The pipeline was constructed in 1988 and placed into service in 1989.

      The Metco Pipeline is a 19-mile, 20-inch diameter pipeline that extends from the interconnect point with the pipeline owned by Gulf States Transmission Corporation to the western end of the Elm Grove System interconnect. The pipeline was constructed and placed in operation in 1990.

      The Ruston System is comprised of a 12-mile, six-inch diameter pipeline, a six-mile, 12-inch diameter pipeline and a 0.5-mile, four-inch diameter pipeline located in Jackson and Lincoln Parishes in north central Louisiana and interconnects with pipelines owned by Southern Natural Gas Co. and Duke Energy Field Services.

      The Panda Pipeline consists of a 20-mile, 20-inch diameter pipeline and an 11-mile, 24-inch diameter pipeline that extends from the eastern portion of the North Louisiana Pipeline to an interstate pipeline that transports natural gas exclusively to a power generation plant. The Panda Pipeline was constructed in 2001 and placed into service in 2002.

      The Dubach Extension consists of an eight-mile, 12-inch diameter pipeline that was constructed as part of our Enhancement Project and is described in further detail below.

      Our Regency Intrastate Pipeline system also includes a natural gas refrigeration conditioning plant. At the plant, we condition natural gas to remove NGLs to ensure that it meets pipeline-quality specifications so that it can be transported on our intrastate pipeline. The NGLs extracted from the raw natural gas at our refrigeration conditioning plant are sold to a third party at the tailgate of the plant.

      Our primary purchasers of pipeline-quality gas on the Regency Intrastate Pipeline system are Alabama Gas Corporation, Southwestern Power and Electric Company, and Duke Energy Field Services, which represented approximately 66%, 10% and 7%, respectively, of the external revenues from such sales for the nine months ended September 30, 2005.

      Enhancement Project. Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result, we have completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. The project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.

      The Regency Intrastate Enhancement Project is a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to extend the pipeline in order to access new sources of supply and markets. We began planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005.

      The total cost of this project is expected to be approximately $140 million. On July 1, 2005, we completed the Dubach extension, which consists of an eight mile, 12-inch diameter pipeline and

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connection the Panda Pipeline to our Dubach processing plant located on our north Louisiana gathering system. The Dubach extension provides the Regency Intrastate Pipeline system with direct access to interstate pipelines owned by Texas Gas Transmission, LLC, Mississippi River Transmission Corp. and Texas Eastern Transmission, LP. that are directly connected to the Dubach processing plant.

      As of October 1, 2005, we had completed construction of the second phase of this project, which includes a 40-mile, 24-inch diameter system loop along a portion of our existing pipeline. This additional pipeline has increased the capacity of the Regency Intrastate Pipeline system by 100 MMcf/d, all of which is currently being utilized.

      In December 2005, we completed construction of the final phase of this project, which includes an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system providing transportation services from several major producing fields in north Louisiana to interstate and intrastate markets in northeast Louisiana, including pipelines owned by Columbia Gulf Transmission Co., Texas Gas Transmission, LLC, Gulf South Pipeline Company, Tennessee Natural Gas Co. and ANR Pipeline Company. We refer to this extension as the Winnsboro extension. The Winnsboro extension extends from the eastern terminus of the North Louisiana Pipeline to northeastern Louisiana.

      In order to increase the efficiency of the system and to facilitate the enhancement, we also added approximately 9,500 horsepower of compression to the system.

      As a result of the completion of the Regency Intrastate Enhancement Project, we are able to transport natural gas produced from the Vernon field, the Elm Grove field and the Sligo field, which are the three largest natural gas producing fields in Louisiana.

      New Transportation Contracts. Prior to the completion of the final phase of the project in December 2005, we were transporting approximately 265 MMcf/d under existing contracts. Additionally we have signed definitive agreements for 249 MMcf/d of firm transportation and 156 MMcf/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining incremental transportation capacity of 130 MMcf/d resulting from the Regency Intrastate Enhancement Project.

      Funding of Project Costs. In July 2005, we amended our credit facilities to provide for $170 million in additional borrowing capacity, consisting of $60 million in additional term loans and $110 million in additional revolving loans. We used these amounts, together with an additional $15 million equity contribution from the HMTF Investors to complete the Regency Intrastate Enhancement Project. For information regarding the terms of the amended and restated credit facilities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements.”

      Interstate Pipeline Specifications. The markets to which the shippers on our Regency Intrastate Pipeline ship natural gas include interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include such matters as hydrocarbon dewpoint, temperature and foreign content including water, sulphur, carbon dioxide and hydrogen sulphide. These specifications vary by interstate pipeline. If the total mix of natural gas shipped by the shippers on our pipeline fails to meet the specifications of a particular interstate pipeline, that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it.

      In certain cases, the mix of natural gas that we transport for shippers on our Regency Intrastate Pipeline does not meet the dewpoint specification of one of our interconnected interstate pipelines. In October 2005, we began construction of a refrigeration plant at Elm Grove to remove hydrocarbons and allow the natural gas to meet these dewpoint specifications. We expect the plant to be completed by the end of April 2006.

      An interstate pipeline curtailed shipments through its existing interconnect with our pipeline in late November 2005. We and our shippers have thus far been able to find alternative markets for all the curtailed gas. If for some reason we are unable to do so during the period prior to completion of the Elm Grove refrigeration plant, we may be required to shut-in non-conforming gas delivered to us for

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transportation. We estimate that a reduction of approximately 25,000 MMBtu/d would substantially restore the total mix of transported gas to these dewpoint specifications.

      Also, lean or processed gas that we transport or are scheduled to transport may be mixed with gas that does not meet dewpoint specifications, which lowers the overall dewpoint of the natural gas stream and allows us to avoid having to shut-in any gas.

Other Assets

      Gulf States Transmission, our small interstate pipeline, consists of approximately 10 miles of 20-inch pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. The pipeline has a certificated capacity of 150 MMcf/d.

Our Contracts

      Gathering and Processing Contracts. We contract with producers to gather raw natural gas from individual wells or central delivery points located near our gathering systems and processing plants. Once we have executed a contract with the producer, we connect the producer’s wells and central delivery points to our gathering lines through which the natural gas is delivered to a processing plant (whether owned and operated by us or a third party) for a fee. We obtain supplies of raw natural gas for our gathering and processing facilities under contracts having terms ranging from month-to-month to twenty years or life of the lease. We categorize our processing contracts in increasing order of commodity price risk as fee-based, percentage-of-proceeds, or keep-whole contracts. Additionally, it is common for a percentage-of-proceeds or keep-whole contract to have a fee component in addition to its commodity-sensitive component. For a description of our fee-based arrangements, percent-of-proceeds arrangements, and keep-whole arrangements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

      For the nine months ending September 30, 2005, the mixture of our gathering and processing contracts by category and by geographic region is set forth in the following table:

	Nature of Contract
	(Measured by volumes)
Geographic Region	Keep-Whole		POP		Fee-Based
North Louisiana		25.3%		58.9%		15.8%
West Texas		18.4%		43.9%		37.8%
Mid-Continent		34.2%		49.5%		16.3%

      Fee Transportation Contracts. We provide natural gas transportation services on the Regency Intrastate Pipeline pursuant to contracts with natural gas shippers. These contracts are all fee-based. Generally, our transportation services are of two types: firm transportation and interruptible transportation. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the capacity is utilized by the shipper, and in some cases the shipper also pays a commodity charge with respect to quantities actually shipped. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped. We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with FERC with respect to transportation authorized under section 311 of the Natural Gas Policy Act.

      Merchant Transportation Contracts. We perform a limited merchant function on our Regency Intrastate Pipeline system. We purchase natural gas from a producer or gas marketer at a receipt point on our system at a price adjusted to reflect our transportation fee and transport that gas to a delivery point on our system at which we sell the natural gas at market price. We regard the total segment margin with

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respect to those purchases and sales as the economic equivalent of a fee for our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the same index price on the date of settlement.

Competition

      The natural gas gathering, processing, marketing and transportation businesses are highly competitive. We face strong competition in each region in acquiring new gas supplies. Our competitors in acquiring new gas supplies and in processing new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer.

      Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors in each region include:

•  North Louisiana: CenterPoint Energy Gas Marketing Company; Gulf South Pipeline L.P.; PanEnergy Louisiana Intrastate, LLC (Pelico).

•  West Texas: Sid Richardson Energy Services Co.

•  Mid-Continent: Duke Energy Field Service, L.P.; ONEOK Energy Marketing and Trading, L.P.; Penn Virginia Corporation.

      In transporting natural gas across north Louisiana, we face major competition from CenterPoint Energy Gas Marketing Company; Gulf South Pipeline, L.P.; Texas Gas Transmission, LLC. Many of our competitors have substantially greater resources, both in capital and in access to shippers’ supplies of natural gas than we do. Competition in natural gas transportation is characterized by price of transportation, the nature of the markets accessible from a transportation pipeline and nature of service.

Risk Management

      To manage commodity price risk, we have implemented a risk management program under which we seek to match sales prices of commodities (especially natural gas) with purchases under our contracts; manage our portfolio of contracts to reduce commodity price risk; optimize our portfolio by active monitoring of basis, swing, and fractionation spread exposure; and hedge a portion of our exposure to commodity prices (especially NGLs).

      To the extent that we purchase or commit contractually to purchase natural gas that we gather and process, we are exposed to commodity price changes in both the natural gas and NGL markets. Operationally, we mitigate this price risk by generally purchasing natural gas and NGLs at prices derived from published indices, rather than at a contractually fixed price and by marketing natural gas and natural gas liquids under similar pricing mechanisms. In addition, we optimize the operations of our processing facilities on a daily basis, for example by rejecting ethane when recovery of ethane as an NGL is uneconomic.

      As a consequence of our processing contract portfolio, we derive a portion of our earnings from a long position in NGL products, resulting from the purchase of natural gas for our account or from the payment of processing charges in kind, that are exposed to commodity price fluctuations. Shortly after the acquisition of our company by the HMTF Investors, we implemented a policy of hedging against this commodity price risk by purchasing a series of contracts relating to swaps of individual NGL products and crude oil puts. Our hedging position and needs to supplement or modify our position are closely monitored by the Risk Management Committee of our general partner. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk” for information regarding the status of these contracts and the accounting treatment

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to be accorded to them. Our policy is not to acquire natural gas futures contracts or derivative products for the purpose of speculating on price changes.

Regulation

      Intrastate Pipeline Regulation. To the extent that our Regency Intrastate Pipeline system transports natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC, under Section 311 of the Natural Gas Policy Act of 1978, or NGPA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of “fair and equitable” rates are subject to refund with interest. NGPA Section 311 rates deemed fair and equitable by FERC are generally analogous to the cost-based rates that FERC deems “just and reasonable” for interstate pipelines under the Natural Gas Act, or NGA. Certain aspects of FERC rate regulation under the NGA are discussed under the section below entitled “Regulation — Interstate Pipeline Regulation.” Additionally, the terms and conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval.

      FERC Pipeline Regulation. Regency Intrastate Gas LLC, or RIGS, is an intrastate pipeline in the state of Louisiana that transports interstate gas under Section 311(a)(2) of the NGPA for many of its shippers. FERC approves Section 311(a)(2) transportation rates for these intrastate pipelines typically on a cost of service basis. FERC requires most of these pipelines, including RIGS, to file triennial rate petitions either justifying its existing rates or requesting new rates. RIGS’ most recent Section 311 rates were established by FERC order dated September 26, 2005, and RIGS is obligated to file its next Section 311 rate case no later than May 1, 2008.

      Under Section 311, intrastate pipelines providing interstate transportation service under NGPA Section 311 may avoid jurisdiction that would otherwise apply under the Natural Gas Act of 1938, or NGA.

      Any failure on our part:

•  To observe the service limitations applicable to transportation service under Section 311,

•  to comply with the rates approved by FERC for Section 311 service,

•  to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or

•  to comply with applicable FERC regulations, the NGPA or certain state laws and regulations

could result in an alteration of our jurisdictional status or the imposition of administrative, civil and criminal penalties, or both.

      Our Regency Intrastate Pipeline system in north Louisiana is subject to regulation by various agencies of the State of Louisiana. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. Louisiana also has agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.

      Transmission Regulation. FERC also has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the Gulf States Transmission Corporation pipeline. Under the Natural Gas Act, rates charged for interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates are subject to refund with interest. Gulf States Transmission holds a FERC-approved tariff setting forth cost-based rates, terms and

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conditions for services to shippers wishing to take interstate transportation service. FERC’s authority extends to:

•  rates and charges for natural gas transportation and related services;

•  certification and construction of new facilities;

•  extension or abandonment of services and facilities;

•  maintenance of accounts and records;

•  relationships between the pipeline and its energy affiliates;

•  terms and conditions of service;

•  depreciation and amortization policies;

•  accounting rates for ratemaking purposes;

•  acquisition and disposition of facilities;

•  initiation and discontinuation of services; and

•  information posting requirements.

      FERC regulation and policy determine whether and to what extent an interstate pipeline’s costs are eligible for inclusion in that pipeline’s cost-of-service for purposes of establishing the pipeline’s maximum “just and reasonable” rates for service. Under new FERC rate policy, pipelines are permitted to include, as part of their cost-of-service, a full income tax allowance for all entities owning the public utility asset, provided that such entities or individuals are subject to an actual or potential tax liability to be paid on income derived from the public utility asset. FERC’s income tax allowance policy is, however, currently being challenged, and may be subject to change in the future. As a consequence, we cannot provide any assurance that we will be able to include an income tax allowance in the cost-of-service used to set Gulf States Transmission Corporation’s maximum just and reasonable rates. Additionally, whether and to what extent an intrastate pipeline company providing service under NGPA Section 311 is allowed to include an analogous income tax allowance in its cost-of-service for ratemaking purposes is currently unclear and is, in any event, likewise subject to change in the future.

      Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

      State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. We are subject to state ratable take and common purchaser statues. The 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 that purchase gas to purchase without undue discrimination as to source of supply or producer. These statues are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. These statues have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

      Natural gas gathering may receive greater regulatory scrutiny at both the state and the federal levels now that FERC has taken a less stringent approach to regulation of the gas gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the Texas Railroad Commission, or TRRC, has approved

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changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. In addition, many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

      Sales of Natural Gas. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The prices at which we sell natural gas are affected by many competitive factors, including the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting interstate transportation, including storage, those segments of the natural gas industry, most notably interstate natural gas transmission companies, that are subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

      Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and NGLs are not currently regulated. Prices of these products are set by the market rather than by regulation. Effective as of January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil, NGLs and other products that allowed for an increase in the cost of transporting oil to the purchaser. The implementation of these regulations has not had a material adverse effect on our results of operations.

Environmental Matters

      General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to the release of hazardous substances or wastes into the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing and operating our plants, pipelines and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with the environmental laws.

      Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil or criminal penalties, requirements to perform investigatory or remedial activities and the issuance of injunctions or construction bans or delays. We have implemented procedures to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our consolidated results of operations or financial condition.

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      The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases and spills are associated with our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases or spills, including those relating to claims for damage to property and persons. In the event of future increase in costs, we may be unable to pass on those increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury or damage to property. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

      Under an omnibus agreement, Regency Acquisition LP will agree to indemnify us in an aggregate amount not to exceed $8.6 million generally for three years after the closing of this offering for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before the closing date. For a discussion of the omnibus agreement, please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

      Hazardous Substances and Waste. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid waste into soils, groundwater and surface water and include measures to control pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous wastes and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of “hazardous substance” into the environment. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances that have been released into the environment. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency, or EPA, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition. We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or analogous state laws.

      We also generate both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the EPA has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. It is possible, however, that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.

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      We currently own or lease properties that have been used over the years by prior owners and by us for natural gas gathering, processing and transportation. Solid waste disposal practices within the midstream gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of or released on or under various properties that are now owned or leased by us during the operating history of those facilities. Notwithstanding the possibility that these dispositions of wastes may have occurred during the ownership of these assets by others, these properties and wastes may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial operations to prevent the migration of contamination.

      It is this possibility that led the management of Regency Gas Services to negotiate for the inclusion of environmental indemnity provisions in the agreement under which it agreed to acquire the El Paso assets in 2003. Those provisions included an indemnity of Regency Gas Services by the El Paso sellers against a variety of environmental claims for a period of five years up to an aggregate of $84 million. They also included an escrow of $9 million relating to claims, including environmental claims, under the El Paso agreement.

      Regency Gas Services has submitted a claim against El Paso for a variety of environmental defects at the former El Paso assets, and El Paso has agreed to maintain $5.4 million in the escrow account to pay any claim amounts for environmental matters ultimately deemed to be covered by El Paso’s indemnity. This amount represents the upper end of the estimated remediation cost calculated by Regency based on the results of its investigations of the former El Paso assets.

      A Phase I environmental study was performed on our west Texas assets by an environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2004. The study indicated that most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote.

      At the time of the negotiation of the agreement to acquire the Duke assets in the first quarter of 2004, management of Regency Gas Services obtained an insurance policy against specified risks of environmental claims up to $10 million. The premiums on the insurance policy were prepaid for a period of 10 years or until February 2014. This policy covers third party claims for on-site and off-site cleanup costs and personal injury/ property damage arising from pre-February 2004 contamination or incidents, with a $100,000 per claim deductible.

      Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are becoming subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practice to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities.

      ODEQ Notice of Violation. In March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent us a notice of violation, alleging that we are operating the Mocane processing plant in Beaver

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County, Oklahoma in violation of the National Emission Standard for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities, or NESHAP, and the requirements to apply for and obtain a federal operating permit (Title V permit). We believe that the basis for the allegations identified in the notice of violation is inapplicable to the Mocane processing plant. If the allegations in the notice of violation ultimately prove to be valid, we could be required to pay a penalty and to implement additional air quality emission controls at the Mocane processing plant, which may include principally a more stringent leak detection and repair program and a program of periodic compliance reports. We do not believe resolution of this notice of violation will have any materially adverse effect on our consolidated results of operations.

      TCEQ Notice of Enforcement. In November 2004, the Texas Commission on Environmental Quality, or TCEQ, sent a Notice of Enforcement, or NOE, to us relating to the operation of the Waha processing plant in 2001 before it was acquired by us. We settled this NOE with the TCEQ in November 2005.

      Absent the physical or operational changes at the Waha processing plant that allegedly occasioned the NOE, the air emissions at the plant would have been limited, based on the plant’s “grandfathered” status under the relevant federal statutory standards, only by historical amounts until 2007. In anticipation of the expiration of that status and regardless of the outcome of the NOE, we submitted to the TCEQ in early February 2005 an application for a state air permit for emissions from the Waha plant predicated on the construction of an acid gas reinjection well and, after completion of the well, the reinjection of the emitted gases. That permit has been issued and requires completion of construction of the well by the end of February 2007. We estimate the capital expenditure relating to the well at $3.5 million.

      Clean Water Act. The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or NPDES, or state permit, or both, must be obtained to discharge pollutants into state and federal waters. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our consolidated results of operation or financial position.

      Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitat. While we have no reason to believe that we operate in any area that is currently designated as a habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause us to incur additional costs or to become subject to operating restrictions or bans in the affected areas.

      Employee Health and Safety. We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

      Safety Regulations. Those pipelines through which we transport mixed NGLs (exclusively to other NGL pipelines) are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA requires any entity that owns or operates liquids pipelines to comply with the regulations under the HLPSA, to permit access to and allow copying

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of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe our liquids pipelines are in substantial compliance with applicable HLPSA requirements.

      Our intrastate pipeline facilities are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers natural gas, crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could have a material adverse effect on our results of operations or financial positions.

      Louisiana administers federal pipeline safety standards under the NGPSA. The Louisiana Office of Conservation, Pipeline Division, monitors Louisiana intrastate pipeline operators to ensure safety and compliance with regulations. Among other things, the Louisiana Office of Conservation conducts pipeline inspections and accident investigations, and it oversees compliance and enforcement, safety programs, and record maintenance and reporting. The “rural gathering exemption” under the NGPSA presently exempts our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future, and that exemption does not apply to our intrastate natural gas pipeline facilities. With respect to recent pipeline accidents in other parts of the country, Congress and the DOT have passed or are considering heightened pipeline safety requirements.

Title to Properties

      Substantially all our pipelines are constructed on rights-of-way, or ROWs, granted by the apparent owners of record of the properties. Lands over which pipeline ROWs have been obtained may be subject to prior liens that have not been subordinated to the ROW grants.

      Our Lakin, Mocane and Lisbon processing plants are located on leased real property. Our Dubach and Waha processing plants are located on property that we own in fee.

      We believe that we have (or will have after the transactions to be effected at the closing of this offering) satisfactory title to all our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Title to substantially all our assets is subject to first and second priority liens and security interests in favor of the lending banks under our credit facilities. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.

      At the closing of this offering, the ownership of the equity of Regency Gas Services will be transferred to us. Substantially all the consolidated tangible assets of Regency Gas Services are owned by its subsidiaries. Thus, we do not anticipate that there will be any transfers of title to the tangible assets owned and operated by Regency Gas Services and its subsidiaries. This transfer of equity ownership of Regency Gas Services may, nevertheless, require consents of current landowners under “change in control” provisions contained in a few of the leases, easements, ROWs, permits and licenses owned by subsidiaries of Regency Gas Services. Some of these are governmental entities. With respect to the transactions to be effected at the closing of this offering, we believe that we have obtained or will obtain prior to the closing sufficient third party consents, permits and authorizations under these leases, easements, ROWs, permits and licenses for us to operate our business in all material respects as described in this prospectus and that any not so obtained will be obtained after the closing of this offering.

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Office Facilities

      We occupy approximately 25,900 square feet of office space at our executive offices at 1700 Pacific Avenue, Dallas, Texas, under a lease that expires at the end of October 2008. Although we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future.

      We also maintain small regional offices located on leased premises in Shreveport, Louisiana; Tulsa, Oklahoma; and Midland and San Antonio, Texas.

Employees

      Regency GP LLC or its affiliates employ approximately 153 employees, of whom 103 are field operating employees and 50 are mid and senior level management and staff.

      None of these employees is represented by a labor union and there are no outstanding collective bargaining agreements to which Regency GP LLC or any of its affiliates is a party. Regency GP LLC believes that it has good relations with its employees.

Legal Proceedings

      We are not a party to any material litigation. See, however, the discussion of the TCEQ NOE and the ODEQ NOV under “— Environmental Matters — TCEQ Notice of Enforcement” and “— Environmental Matters — ODEQ Notice of Violation.” Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.

      We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

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MANAGEMENT

Management of Regency Energy Partners LP

      Because our general partner is a limited partnership, its general partner, Regency GP LLC, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of Regency GP LLC or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

      The directors of Regency GP LLC will oversee our operations. Regency GP LLC has appointed three members to its board of directors, all of whom we believe will be independent as defined under the independence standards established by the Nasdaq National Market. The board of directors of Regency GP LLC has established six committees of the board of directors: executive committee; conflicts committee; audit committee; risk management committee; compensation committee; and nominating committee. The primary functions of each committee are described below.

      Executive Committee. The board of directors of Regency GP LLC has appointed an executive committee that currently consists of three directors. The executive committee will exercise the powers and authority of the board of directors to direct our business and affairs in intervals between meetings of the board of directors of Regency GP LLC.

      Conflicts Committee. Three members of the board of directors of Regency GP LLC have been appointed to serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the stock exchange or market on which we list our common units and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

      Audit Committee. In addition, the board of directors of Regency GP LLC has appointed an audit committee of five directors, three of whom the board of directors has determined meet the independence and experience standards established by the Nasdaq National Market and the Securities Exchange Act of 1934, as amended. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee also will be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

      Risk Management Committee. The board of directors of Regency GP, LLC has also established a risk management committee that currently consists of three directors, one of whom is an ex-officio member who does not vote. The purpose of the risk management committee is to monitor and oversee those areas of our operations, such as hedging and insurance activities, involving special risks. The risk management committee shall exercise the power and authority of the board of directors and assist the board of directors in fulfilling its responsibilities in connection with our activities and operations that pose special risks.

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      Compensation Committee. The compensation committee of the board of directors consists of four directors, one of whom is an ex-officio member who does not vote. The compensation committee will make recommendations, after investigation and evaluation of pertinent matters, to the board of directors relating to compensation of the Chief Executive Officer and other executives. Except as otherwise required by applicable laws, regulations or Nasdaq listing standards, all such compensation decisions shall be considered and made by the board of directors.

      Nominating Committee. The nominating committee of the board of directors currently consists of four directors. The nominating committee is responsible for establishing criteria for selecting new directors and actively seeking individuals to be included in the slate of director nominees recommended by the nominating committee to the board of directors. The nominating committee shall also determine whether a director or prospective director is independent.

      The officers of Regency GP LLC will manage the day-to-day affairs of our business.

Directors and Executive Officers

      The following table shows information regarding the current directors and executive officers of Regency GP LLC. Directors are elected for one-year terms.

Name	Age		Position with Regency GP LLC
James W. Hunt(1)(4)(5)		61	Chairman of the Board, President and Chief Executive Officer
Michael L. Williams		46	Executive Vice President and Chief Operating Officer
Stephen L. Arata		39	Executive Vice President and Chief Financial Officer
William E. Joor III		65	Executive Vice President, Chief Legal and Administrative Officer and Secretary
Durell J. Johnson		43	Vice President, Operations and Engineering
Lawrence B. Connors		54	Vice President, Finance and Chief Accounting Officer
Alvin Suggs		52	Vice President and General Counsel
Joe Colonnetta(1)(4)(6)		43	Director
Jason H. Downie(1)(4)(5)(6)		35	Director
A. Dean Fuller(2)(3)		58	Director
Jack D. Furst		46	Director
J. Edward Herring(2)(6)		35	Director
Robert D. Kincaid(2)		44	Director
Gary W. Luce(5)		45	Director
Robert W. Shower(2)(3)(6)		68	Director
J. Otis Winters(2)(3)(4)		73	Director

(1)	Member of the Executive Committee. Mr. Colonnetta is chairman of this committee.
(2)	Member of the Audit Committee. Mr. Shower is chairman of this committee.
(3)	Member of Conflicts Committee. Mr. Fuller is chairman of this committee.
(4)	Member of Compensation Committee. Mr. Downie is chairman of this committee. Mr. Hunt is an ex-officio member.
(5)	Member of Risk Management Committee. Mr. Luce is chairman of this committee. Mr. Hunt is an ex-officio member.
(6)	Member of Nominating Committee. Mr. Colonnetta is chairman of this committee.

      James W. Hunt was elected Chairman of the Board of Directors of Regency GP LLC and Regency Gas Services in November 2005. Mr. Hunt has served as President and Chief Executive Officer of

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Regency GP LLC from September 2005 to present. Mr. Hunt has, since his election effective December 1, 2004, served as President, Chief Executive Officer and Director of Regency Gas Services LLC. From 1978 until January 1981, Mr. Hunt served as President and Chief Executive Officer of Diamond M Company, a major offshore drilling company and the predecessor of Diamond Offshore Company. From 1981 through 1987, he served as President and Chief Executive Officer of Cenergy Corporation, a NYSE listed oil and gas exploration, production and pipeline company. During the period from 1987 until December 2004, Mr. Hunt was engaged in energy investment banking, first as head of the Houston office of Lehman Brothers Incorporated and most recently as head of the U.S. Energy Group of UBS Securities LLC. Mr. Hunt is an attorney and member of the State Bar of Texas.

      Michael L. Williams, P.E., was elected Executive Vice President and Chief Operating Officer of Regency GP LLC in September 2005. From December 2004 to the present, Mr. Williams served as Executive Vice President and Chief Operating Officer of Regency Gas Services LLC. Mr. Williams served as Vice President of Engineering and Operations from October 2002 through September 2004 heading up operations and engineering at Energy Transfer Partners, L.P. Mr. Williams also served as Vice President of Engineering and Operations for Aquila Inc. from 2000 through September 2002 where he was responsible for the Operation and Engineering of Aquila’s gas gathering, processing, fractionation, and storage assets.

      Stephen L. Arata was elected Executive Vice President and Chief Financial Officer of Regency GP LLC in September 2005. From June 2005 to the present, Mr. Arata served as Executive Vice President and Chief Financial Officer of Regency Gas Services LLC. From September 1996 to June 2005, Mr. Arata worked for UBS Investment Bank, covering the power and pipeline sectors; he was Executive Director from 2000 through July 2005. Prior to UBS, Mr. Arata worked for Deloitte Consulting, focusing on the energy sector.

      William E. Joor III was elected Executive Vice President, Chief Legal and Administrative Officer and Secretary of Regency GP LLC in September 2005. Mr. Joor has, since his election effective January 1, 2005, served as Executive Vice President, Chief Legal and Administrative Officer and Secretary of Regency Gas Services LLC. From May 1966 through December 1973, Mr. Joor was associated with, and from then until December 31, 2004 was a partner of, Vinson & Elkins LLP. Mr. Joor’s area of specialization was the law of corporate finance and mergers and acquisitions with particular emphasis in the energy sector.

      Durell J. Johnson, P.E., was elected Vice President of Operations and Engineering of Regency GP LLC in September 2005. From December 2004 to the present, Mr. Johnson served as Vice President of Operations and Engineering of Regency Gas Services LLC. Mr. Johnson was Director of Engineering for Energy Transfer Partners, L.P. from October 2003 through October 2004 providing engineering support for all of Energy Transfer’s midstream operations. Mr. Johnson was Vice President of engineering for Garrison LTD. from October 2002 until October 2003 where he was responsible for drilling and facilities operations. Mr. Johnson was Manager of Engineering and Construction at Aquila Inc. from 1999 until October 2002. Mr. Johnson has 20 years of diversified experience in the natural gas industry.

      Lawrence B. Connors was elected Vice President of Finance and Chief Accounting Officer of Regency GP LLC in September 2005. From December 2004 to the present, Mr. Connors served as Vice President, Finance and Chief Accounting Officer of Regency Gas Services LLC. From June 2003 through November 2004, Mr. Connors served as Controller of Regency Gas Services LLC. From August 2000 through November 2001, Mr. Connors was an independent accounting and financial consultant. From 2001 through May 2003 Mr. Connors was a Registered Representative with Foster Financial Group. From 1996 through July 2000, Mr. Connors was the Controller and Chief Accounting Officer of Central and South West Corporation, or CSW; he had managerial responsibilities at three CSW operating companies and CSW Services. Prior to his employment at CSW, he was with Arthur Andersen working with energy and health care audit clients. Mr. Connors is a Certified Public Accountant.

      Alvin Suggs was elected Vice President and General Counsel of Regency GP LLC in September 2005. From June 2005 to the present, Mr. Suggs served as Vice President and General Counsel of Regency Gas Services LLC. From June 2003 to June 2005, Mr. Suggs engaged in the private practice of law representing clients in the energy sector, first as a sole practitioner and, after June 2004, with

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Thompson & Knight, LLP. Mr. Suggs served as Vice President and Associate General Counsel with El Paso Energy Corporation and General Counsel of El Paso Field Services, L.P. from September 1999 through June 2003. Mr. Suggs served as Senior Counsel to El Paso Field Services, L.P. and El Paso Energy Marketing, L.P. from September 1997 to September 1999, and from 1987 to 1999 he served Texas Oil & Gas Corp., American Oil and Gas Corporation and KN Energy, Inc. in various capacities from Counsel to Assistant General Counsel. Prior to that service, Mr. Suggs was in private practice of law for five years, and also served as Assistant District Attorney for the Fifth Circuit Court District in Mississippi in 1978.

      Joe Colonnetta was elected to the Board of Directors of Regency GP LLC in September 2005 and served as Chairman of the Board of Directors until November 2005. From December 2004 to the present, Mr. Colonnetta has served as a director of Regency Gas Services LLC, including service as Chairman of the Board until November 2005. Mr. Colonnetta is a partner at Hicks, Muse, Tate & Furst, Incorporated. Mr. Colonnetta joined Hicks Muse in 1998. Prior to joining Hicks Muse, Mr. Colonnetta was a partner with Metropoulos and Co., an affiliate of Hicks Muse. Mr. Colonnetta is also Chairman of the Board of Directors of TexStar Field Services and BlackBrush Oil & Gas, and he serves on the Board of Directors of Swift & Company.

      Jason H. Downie was elected to the Board of Directors of Regency GP LLC in September 2005. From December 2004 to the present, Mr. Downie has served as a director of Regency Gas Services LLC. Mr. Downie is a partner of Hicks, Muse, Tate & Furst, Incorporated and has been with the firm since September 2000. From June 1999 to August 2000, Mr. Downie was an associate at Rice Sangalis Toole & Wilson, a mezzanine private equity firm based in Houston, Texas, and from June 1992 through June 1997, Mr. Downie served in various capacities with Donaldson, Lufkin & Jenrette in New York, lastly as an Associate Position Trader in their Capital Markets Group. From June 1997 to June 1999, Mr. Downie attended the McCombs School of Business at the University of Texas. Mr. Downie also serves on the Board of Directors of TexStar Field Services, BlackBrush Oil & Gas and Activant Solutions Holdings Inc.

      A. Dean Fuller was elected to the Board of Directors of Regency GP LLC on November 14, 2005. Having sold in 1993 a company he co-founded, Mr. Fuller become President and Chief Executive Officer of Transok, Inc., the natural gas pipeline subsidiary of Central and South West Corporation, until its sale in 1996. Mr. Fuller continued to manage the fuels and gas marketing function of CSW until late 2000 at which time he became Senior Vice President of the midstream business of Aquila, Inc. At the time of the acquisition of Aquila’s midstream business by Energy Transfer, Mr. Fuller continued to manage those assets as Senior Vice President, and served as President of Oasis Pipeline Company after its acquisition by Energy Transfer. Mr. Fuller resigned his positions with Energy Transfer in August 2004.

      Jack D. Furst was elected to the Board of Directors of Regency GP LLC on December 8, 2005. Mr. Furst is a partner with Hicks, Muse, Tate & Furst, Incorporated and has been with the firm since its formation in 1989. From 1987 to 1989, Mr. Furst served as a vice president and subsequently a partner of Hicks & Haas. From 1984 to 1986, Mr. Furst was a merger & acquisitions/corporate finance specialist for The First Boston Corporation in New York. Before joining First Boston, Mr. Furst was a financial consultant at Price Waterhouse. Mr. Furst received his MBA from the Graduate School of Business at the University of Texas. Mr. Furst also serves on the Board of Directors of Activant Solutions Holdings Inc. and various other privately held companies.

      J. Edward Herring was elected to the Board of Directors of Regency GP LLC in September 2005. From December 2004 to the present, Mr. Herring has served as a director of Regency Gas Services LLC. Mr. Herring is a partner at Hicks, Muse, Tate & Furst, Incorporated and has been with the firm since 1998. From 1996 to 1998, Mr. Herring attended Harvard Business School. From 1993 to 1996, Mr. Herring was an investment banker with Goldman, Sachs & Co. Mr. Herring also serves on the Board of Directors of Swift & Company, BlackBrush Oil & Gas, TexStar Field Services and Swett & Crawford.

      Robert D. Kincaid was elected to the Board of Directors of Regency GP LLC in September 2005. From January 2005 to the present, Mr. Kincaid has served as a director of Regency Gas Services LLC. Mr. Kincaid is a co-founder, with Mr. Luce, and Managing Director of K-L Energy Partners, LLC, a

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private equity management firm formed in April 2004 to focus on investments in the midstream and downstream energy and power sectors. From October 1998 until December 2003, Mr. Kincaid was a principal of Haddington Ventures, LLC, another private equity management firm focused on energy-related investing. From December 2003 until March 2004, Mr. Kincaid served as a consultant to Haddington Ventures. Mr. Kincaid served as Treasurer of TPC Corporation, a firm engaged in the natural gas marketing, pipeline and storage sectors, from 1992 until its sale to PacifiCorp in April 1997. Mr. Kincaid began his career in investment banking and mezzanine fund management in Houston, Texas.

      Gary W. Luce was elected to the Board of Directors of Regency GP LLC in September 2005. From January 2005 to the present, Mr. Luce has served as a director of Regency Gas Services LLC. Mr. Luce is a co-founder, with Mr. Kincaid, and has been Managing Director of K-L Energy Partners, LLC since its inception in April 2004. During the period from November 2002 until April 2004, Mr. Luce, in order to comply with the non-competition provisions of his employment agreement with Reliant Resources, Inc., acted as an independent financial consultant. Mr. Luce served as a member of the senior management team for two public energy-related companies, EOTT Energy Partners, LP from April 1994 to December 1998 and Reliant Resources, Inc. from October 1999 to November 2002. Mr. Luce also served in various capacities with McKinsey & Company, Inc., the international management-consulting firm, most recently as a downstream energy practice principal.

      Robert W. Shower was elected to the Board of Directors of Regency GP LLC on November 14, 2005. During the period from 1964 through 1986, Mr. Shower was employed by The Williams Companies, ultimately serving as Executive Vice President, Finance and Administration, Chief Financial Officer and a director. Since then, Mr. Shower has served as a managing director of Shearson Lehman Hutton Incorporated (1986-1990), Vice President and Chief Financial Officer of AmeriServe (1990-1991), Senior Vice President, Corporate Development for Albert Fisher, Inc. (1991-1992) and Executive Vice President, Chief Financial Officer and a director of Seagull Energy Corporation (1992-1996). Currently, Mr. Shower is a member of the board of directors and chairman of the audit committee of Edge Petroleum Corporation. Mr. Shower was formerly a member of the board of directors and chairman of the audit committee of Lear Corporation, Highlands Insurance Group, Inc. and Nuevo Energy Company.

      J. Otis Winters was elected to the Board of Directors of Regency GP LLC on November 14, 2005. The following are exemplary of Mr. Winters’ extensive business experience: Vice President of Warren American Oil Company (1964-1965); President and a director of Educational Development Corporation (1966-1973); Executive Vice President and a director of The Williams Companies, Inc. (1973-1977); Executive Vice President and a director of First National Bank of Tulsa (1978-1979); President and a director of Avanti Energy Corporation (1980-1987); Managing Director of Mason Best Company (1988-1989); Chairman, director and co-founder of The PWS Group (1990-2000); and from 2001 to date Chairman and Chief Executive Officer of Oriole Oil Company. Mr. Winters has served on the board of directors of 20 publicly owned corporations, including Alton Box Board Company, AMFM, Inc., AMX Corporation, Dynegy, Inc., Liberty Bancorp., Inc., Tidel Engineering, Inc., Trident NGL, Inc. and Walden Residential Properties, Inc.

Reimbursement of Expenses of Our General Partner

      Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will, however, be reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.

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Executive Compensation

      We, our general partner and Regency GP LLC were formed in September 2005. Because our general partner is a limited partnership, its general partner, Regency GP LLC, will manage our operations and activities through its board of directors and executive officers. All of our officers and employees are employed by Regency GP LLC. Because they are employees of Regency GP LLC, the compensation of the executive officers of Regency GP LLC (other than any awards under the benefit plans described below) will be set and paid by Regency GP LLC. Officers and employees of Regency GP LLC may participate in employee benefit plans and arrangements sponsored by Regency GP LLC or its affiliates, including plans that may be established in the future.

      Our chief executive officer and our chief operating officer were employed by Regency Gas Services LLC on December 1, 2004. Each of our three other most highly compensated executive officers were employed by Regency Gas Services LLC on January 1, 2005 or later. All these officers now hold the same positions with Regency GP LLC. The following table sets forth the current rates of compensation being paid to our chief executive officer and our four other most highly compensated executive officers by Regency GP LLC, which are the same rates at which these officers were compensated by Regency Gas Services LLC. We refer to these executives as the “named executive officers” elsewhere in this prospectus.

Summary Compensation Table

		Annual
		Compensation				Long-Term
						Compensation(4)
				Other
		Annual		Compensation				Exercise
		Salary and				Common Units		or Strike
Name and Principal Position		Bonuses(1)		(2)(3)		Underlying Options		Price(5)
James W. Hunt
	President, Chief Executive Officer and Chairman of the Board	$	246,000	$	4,200		100,000
Michael L. Williams
	Executive Vice President and Chief Operating Officer		215,250		3,675		40,000
Stephen L. Arata
	Executive Vice President and Chief Financial Officer		205,000		—		35,000
William E. Joor III
	Executive Vice President and Chief Legal and Administrative Officer		205,000		3,500		35,000
Alvin Suggs
	Vice President and General Counsel		184,500		2,250		15,000

(1)

The board of directors of Regency Gas Services LLC adopted the Regency Gas Services LLC Annual Performance Incentive Plan (or the Annual Incentive Plan) in May 2005. Substantially all our employees, including each of the named executive officers, are participants in the Annual Incentive Plan. We anticipate that Regency GP LLC will adopt and continue the plan. The Compensation Committee of Regency Gas Services LLC has been directed to administer the Annual Incentive Plan and, in awarding bonuses, the Compensation Committee will consider a number of factors, including a performance goal for calendar year 2005 of $60 million in EBITDA. These amounts include a portion of the bonuses we expect to award in February 2006. Effective upon completion of this offering, the board of directors of Regency GP LLC has approved salary levels for 2006 in the following amounts: Mr. Hunt — $400,000; Mr. Williams — $300,000; Mr. Arata — $250,000; and Mr. Joor — $215,000. The amounts paid pursuant to these salary levels will be prorated from completion of this offering to December 31, 2006.

(2)

These amounts include the contributions of Regency Gas Services LLC to our Section 401(k) plan for an entire year assuming that each of the named executive officers continues to make contributions at the same rate as each has done since the plan’s adoption in May 2005.

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(3)	These amounts do not include perquisites because the aggregate amount of such benefits does not exceed either $50,000 or 10% of the total of annual salary and bonus reported for the respective officers.
(4)	Regency GP LLC has adopted a Long Term Incentive Plan. Please read the description of the plan under “— Long Term Incentive Plan.”
(5)	The options will have an exercise price equal to the initial public offering price and will vest and may be exercised in one-third increments on the anniversary of the grant date over a period of three years.

      Amounts reflected in the preceding table do not include limited partner interests that will be allocated to certain members of management in connection with this offering and the exchange of their Class B Units in HMTF Regency, L.P. For a description of these units, please read “Certain Relationships and Related Party Transactions — Limited Partner Interests to be Received by Certain Members of Management.”

Employment and Severance Agreements

      At the time of their employment by Regency Gas Services LLC on December 1, 2004, both James W. Hunt, President and Chief Executive Officer, and Michael L. Williams, Executive Vice President and Chief Operating Officer, entered into employment agreements with Regency Gas Services LLC. The agreements now provide for a term of three years, a base salary at the level reflected in the table under “— Executive Compensation,” participation by the employee in the Incentive Plan and other benefit plans adopted by the employer, and the award of the Class B Units of limited partnership interests in HMTF Regency LP described under “Security Ownership of Certain Beneficial Owners and Management.”

      In each case, the agreement provides that the employee’s employment will terminate on the employee’s death and may terminate on his disability, In addition, the employer may terminate the agreement at any time for “cause” (as defined) and, at any time after the expiration of the first six months, without cause. The employee may terminate the agreement at any time for “good reason” (as defined) and, at any time after the first six months, without good reason. The employee may also terminate his employment without good reason during the 30 days following a “change of control” (as defined). In each case, if employee’s employment is terminated by death or disability or by the employer without cause or by the employee for good reason, the employee or his estate will be entitled to the severance amount described below. If employee’s employment is terminated for any other reason, the employee is entitled only to his base salary through the date of termination and any vested amounts under employee benefit plans. The severance amount is, generally, twice the sum of employee’s annual base salary and the bonus received or due for the calendar year preceding the year in which the date of termination occurs. Each employee has agreed, for a period of at least two years following the date of termination of his employment, not to compete with the employer and not to solicit the employer’s customers, suppliers, employees or other of the employer’s business relations. We anticipate these agreements will be assigned by Regency Gas Services LLC to Regency GP LLC.

      At the time of his employment by Regency Gas Services LLC, William E. Joor III entered into a severance agreement with the employer. The severance agreement generally provides that, if at any time during the three years commencing on the date of his employment, January 1, 2005, Mr. Joor’s employment is terminated because of death or disability or by the employer without “cause” (as defined) or by Mr. Joor for “good reason” (as defined), the employee or his estate will be entitled to a severance amount as follows: The severance amount is $600,000 if the termination occurs during the first year, declining by $200,000 per year thereafter.

Compensation of Directors

      Any officer of Regency GP LLC who also serves as a director (Mr. Hunt) will not receive additional compensation. Directors who are not officers or employees of Regency GP LLC will receive (a) a $25,000 annual cash retainer fee, (b) $1,000 for each board meeting attended in person, (c) $500 for each telephonic board meeting attended, (d) $500 for each committee meeting attended and (e) $500 per day

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for consulting services, to the extent such services are requested. These directors will also be eligible for awards under our Long-Term Incentive Plan. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Long-Term Incentive Plan

      General. Regency GP LLC has adopted a Long-Term Incentive Plan (the “Plan”) for employees, consultants and directors of Regency GP LLC and its affiliates who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. We expect that the Plan will provide for the grant of restricted units, phantom units, unit options and substitute awards. With respect to unit options and phantom units, distribution equivalent rights, or DERs may be granted. In addition, unit distribution rights, or UDRs, may be granted with respect to restricted units. Subject to adjustment for certain events, an aggregate of 2,865,584 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy Regency GP LLC’s tax withholding obligations will be available for delivery pursuant to other awards. The Plan will be administered by the compensation committee of Regency GP LLC’s board of directors.

      Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or Regency GP LLC, subject to any contrary provisions in the award agreement.

      If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the grant agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by Regency GP LLC in the open market, common units already owned by Regency GP LLC, common units acquired by Regency GP LLC directly from us or any other person, newly issued common units or any combination of the foregoing. Regency GP LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

      Distributions made by us on restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units pursuant to any UDRs granted in tandem with such restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit. We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

      Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant. Upon exercise of a unit option, Regency GP LLC will acquire common units in the open market at a price equal to the prevailing price on the principal

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national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner or newly issued common units, or any combination of the foregoing. Regency GP LLC will be entitled to reimbursement by us for the difference between the cost incurred by Regency GP LLC in acquiring the common units and the proceeds received by Regency GP LLC from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Regency GP LLC will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

      Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, Regency GP LLC or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

      Termination of Long-Term Incentive Plan. Regency GP LLC’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. Regency GP LLC’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of Regency GP LLC may increase the number of common units that may be delivered with respect to awards under the Plan.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

      The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

•  each person who then will own beneficially 5% or more of our units;

•  each member of the board of directors of Regency GP LLC;

•  each named executive officer of Regency GP LLC; and

•  all directors and executive officers of Regency GP LLC, as a group.

      Ownership information regarding the common and subordinated units set forth in the following table is derived from:

•  the holdings thereof by HMTF Regency, L.P. and the resulting economic interest therein of the persons named in the table pursuant to their ownership of Class A Units of HMTF Regency, L.P.; or

•  the exchange of Class B Units and Class D Units of net profits interests in HMTF Regency, L.P. held by persons named in the table prior to this offering for common and subordinated units.

      These transactions are described in detail under “Certain Relationships and Related Party Transactions — Limited Partner Interests to be Received by Certain Members of Management” and “— Limited Partner Interests to be Received by Certain Directors.” The specific numbers of units to be so received by these persons will be determined based on formulas set forth in the partnership agreement of HMTF Regency, L.P. and will vary depending on the indicative market capitalization of Regency Energy Partners LP derived from the $20.00 initial offering price.

			Percentage of					Percentage of
			Outstanding					Outstanding			Percentage
	Common		Common			Subordinated		Subordinated			of Total
Name of Beneficial Owner	Units		Units			Units		Units			Units
HMTF Investors(1)		4,714,004		24.7	%		16,820,617		88.0	%		56.4	%
James W. Hunt(2)(3)		223,730		1.2			798,317		4.2			2.7
Michael L. Williams(2)(3)		127,846		0.7			456,181		2.4			1.5
Stephen L. Arata(2)(3)		63,923		0.3			228,091		1.2			0.8
William E. Joor III(2)(3)		95,884		0.5			342,136		1.8			1.1
Durell J. Johnson(2)(3)		19,177		0.1			68,427		0.4			0.2
Lawrence B. Connors(2)(3)		19,177		0.1			68,427		0.4			0.2
Alvin Suggs(2)(3)		19,177		0.1			68,427		0.4			0.2
Joe Colonnetta(1)		4,714,004		24.7			16,820,617		88.0			56.4
Jason H. Downie(1)		4,714,004		24.7			16,820,617		88.0			56.4
A. Dean Fuller		—		—			—		—			—
Jack D. Furst(1)		4,714,004		24.7			16,820,617		88.0			56.4
J. Edward Herring(1)		4,714,004		24.7			16,820,617		88.0			56.4
Robert D. Kincaid(4)		9,921		0.1			35,400		0.2			0.1
Gary W. Luce(4)		9,921		0.1			35,400		0.2			0.1
J. Otis Winters		—		—			—		—			—
Robert W. Shower		—		—			—		—			—
All directors and executive Officers as a group (16 persons)		5,302,758		27.8			18,921,424		99.0			63.4

(1)  These units will be held by HMTF Regency, L.P., the ultimate general partner of which is HM5/ GP LLC, an affiliate of Hicks Muse. HM5/ GP LLC may be deemed the beneficial owner of the units

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	held by HMTF Regency, L.P. by virtue of its control of HMTF Regency, L.P. Each of John Muse, Jack Furst, Joe Colonnetta, Peter Brodsky, Andrew Rosen, Jason H. Downie, J. Edward Herring and Eric Lindberg are partners of Hicks, Muse and, in such capacity, exercise investment discretion with respect to securities controlled by HM5/ GP LLC. Consequently, each of Messrs. Muse, Furst, Colonnetta, Brodsky, Rosen, Downie, Herring and Lindberg may be deemed to beneficially own all or a portion of the units owned of record by HMTF Regency, L.P. John Muse also is the sole manager of HM/5GP LLC. As a result, in such capacity as manager of HM5/ GP LLC, Mr. Muse may be deemed to beneficially own the units owned of record by HMTF Regency, L.P. Each of Messrs. Muse, Furst, Colonnetta, Brodsky, Rosen, Downie, Herring and Lindberg disclaims beneficial ownership of units not owned of record by him.
(2)	Each of these executive officers disclaims beneficial ownership of any common and subordinated units held by HMTF Regency, L.P. resulting from his ownership of Class A Units of HMTF Regency, L.P. by each such person as he does not have voting or dispositive control of these units. These units include the following: Mr. Hunt — 25,665 common and 91,579 subordinated; Mr. Williams — 6,679 common and 23,831 subordinated; Mr. Arata — 6,679 common and 23,831 subordinated; Mr. Joor — 6,679 common and 23,831 subordinated; Mr. Johnson — 2,671 common and 9,532 subordinated; Mr. Connors — 6,679 common and 23,831 subordinated; and Mr. Suggs — 2,671 common and 9,532 subordinated. Each of these executive officers will be treated as regards his ownership of Class A Units, in the same manner as any other HMTF Investor. The address of each of these individuals is 1700 Pacific, Suite 2900, Dallas, Texas 75201.
(3)	The remaining common and subordinated units owned beneficially by these individuals will be acquired on exchange of Class B Units of HMTF Regency, L.P. in the manner described under “Certain Relationships and Related Party Transactions — Partnership Interests to be Received by Executive Officers.”
(4)	Each of these directors disclaims beneficial ownership of any common and subordinated units held by HMTF Regency, L.P. resulting from his ownership of Class A Units of HMTF Regency L.P. by each such person as he does not have voting or dispositive control of these units. These units include the following: Mr. Luce — 6,679 common and 23,831 subordinated; and Mr. Kincaid — 6,679 common and 23,831 subordinated. Each of these directors will be treated, as regards his ownership of Class A Units, in the same manner as any other HMTF Investor. The address of each of these individuals is 1700 Pacific, Suite 2900, Dallas, Texas 75201.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

      After this offering, our general partner and its affiliates will own 5,353,896 common units and 19,103,896 subordinated units representing a 62.7% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

      The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Regency Energy Partners LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

FORMATION STAGE

The consideration received by our general partner and its affiliates for the contribution of the assets and liabilities to us	• 5,353,896 common units;
	• 19,103,896 subordinated units;
	• 2% general partner interest;
	• the incentive distribution rights; and
	• $197.0 million cash payment from the proceeds of the offering to reimburse them for capital expenditures comprising most of the initial investment by the HMTF Investors in Regency Gas Services LLC.

OPERATIONAL STAGE

Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions of 98% to the unitholders pro rata, including our general partner and its affiliates, as the holders of an aggregate 5,353,896 common units and 19,103,896 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions that exceed the highest target level.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.1 million on its 2% general partner interest and $34.2 million on their common and subordinated units.
Payments to our general partner and its affiliates	Our general partner and its affiliates will be entitled to reimbursement for all expenses it incurs on our behalf, including salaries and employee benefit costs for its employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The

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	partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

LIQUIDATION STAGE

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read “How We Make Cash Distributions.”

Agreements Governing the Transactions

      We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

      Upon the closing of this offering, we will enter into an omnibus agreement with Regency Acquisition LP pursuant to which Regency Acquisition LP will agree to indemnify us after the closing of this offering against certain environmental and related liabilities arising out of or associated with the operation of the assets before the closing date of this offering. This indemnification obligation will terminate three years after the closing of this offering. There is an aggregate cap of $8.6 million on the amount of indemnity coverage for environmental and related liabilities. In addition, we are not entitled to indemnification until the aggregate amount of all claims under the omnibus agreement exceed $250,000. Liabilities resulting from a change of law after the closing of this offering are excluded from the environmental indemnity by Regency Acquisition LP for the unknown environmental liabilities.

      Regency Acquisition LP will also indemnify us for liabilities related to:

•  certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to us are located and failure to obtain certain consents and permits necessary to conduct our business that arise within two years after the closing of this offering; and

•  certain income tax liabilities attributable to the operation for the assets contributed to us prior to the time they were contributed.

Amendments

      The omnibus agreement may not be amended without the prior approval of the conflicts committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of our common units.

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Competition

      Regency Acquisition LP will not be restricted under the omnibus agreement from competing with us. Regency Acquisition LP may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct or dispose of those assets.

Related Party Transactions Prior to the HMTF Investors’ Acquisition of Regency Gas Services LLC

      Cardinal Gas Services Acquisition. On April 1, 2004, Regency Gas Services LLC, our predecessor, acquired Cardinal Gas Services LLC, a gas processing business, for total cash consideration of $3.5 million. At the time of the acquisition, three former executive officers of the Regency Gas Services LLC owned a portion of the equity interest in Cardinal Gas Services.

      Management Fees. Regency Gas Services LLC paid $0.2 million in management fees in 2004 and 2003 for corporate development and administrative services to Charlesbank Capital Partners LLC, which was an affiliate of Regency Gas Services LLC at the time the services were rendered.

      Acquisition Expenses. In 2003, Regency Gas Services LLC incurred $0.6 million of acquisition expenses on behalf of the Regency Services LLC, its parent company, which is included in advances to affiliates at December 31, 2003. These advances were settled prior to the closing of its acquisition by the HMTF Investors.

      Consulting Contracts. Regency Gas Services LLC had consulting contracts in place with two former directors. The contracts have been terminated and the amounts paid under these contracts in 2004 and 2003 were not material to Regency Gas Services LLC’s results of operations.

Limited Partner Interests to be Received by Certain Members of Management

      Regency Gas Services LLC was acquired in December 2004 by the HMTF Investors through the use of a Delaware limited partnership HMTF Regency, L.P. The HMTF Investors purchased units of limited partnership interests (Class A Units) in HMTF Regency, L.P. for cash, which was used to provide part of the purchase price for Regency Gas Services LLC. The HMTF Investors include the executive officers of Regency Gas Services LLC and now Regency GP LLC, each of whom purchased Class A Units of HMTF Regency, L.P. on the same terms as each other HMTF Investor.

      At the time of the acquisition, two members of our management, the Chief Executive Officer and the Chief Operating Officer, were awarded net profits interests in the form of Class B Units in HMTF Regency, L.P. Subsequently, our Chief Legal Officer, Chief Financial Officer and other executive officers were also awarded Class B Units.

      The Class B Units were designed to provide incentives to management to enhance the value of the investment by HMTF Regency, L.P. in Regency Gas Services LLC represented by the Class A Units. Under the partnership agreement, the economic benefit of the Class B Units was to be conferred at the time of liquidation and sale of the investment for cash and the distribution of the cash to the holders of both Class A Units and Class B Units. The partnership agreement provides for distributions to be made to the holders of the Class B Units only after the holders of Class A Units have received distributions equal to a return of 150% of the investment by those holders in Class A Units or, alternatively, various rates of return on investment.

      The consummation of this offering and the related formation transactions will not result in the liquidation of Regency Gas Services LLC. They will, however, result in realization of value by the holders of the Class A Units as a result of the receipt by HMTF Regency, L.P. of common and subordinated units and interests in our general partner. Consequently, the general partner of HMTF Regency, L.P. (Hicks Muse) has determined that the common units, subordinated units and general partner interests to be received by HMTF Regency, L.P. as a result of those transactions will be allocated among the holders of the Class A Units and Class B Units as if HMTF Regency, L.P. were to be liquidated in accordance with the partnership agreement.

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      Upon consummation of this offering, HMTF Regency, L.P. will receive common and subordinated units issued by us, as well as interests in our general partner. Those units and interests will be allocated between the holders of the Class A Units and Class B Units based on the partnership agreement liquidation provisions as follows:

•  The total number of common and subordinated units and general partner interests issued or transferred to HMTF Regency, L.P. will be valued at the initial offering price per common unit.

•  From that aggregate number of units and interests, a number of units and interests with an equivalent value of $317.3 million (representing a 150% return on the aggregate investment in Class A Units plus transaction expenses) will be allocated to the Class A Unit holders.

•  Of the remainder, 87.5% will be allocated to the Class A Unit holders and 12.5% will be allocated to the Class B Unit holders as a group.

•  The common and subordinated units allocable to the holders of Class A Units will continue to be held by HMTF Regency, L.P.

•  The common and subordinated units allocable to the holders of Class B Units will be distributed to those holders in exchange for their Class B Units.

•  The common and subordinated units and interests so distributed to the group of Class B Unit holders will be allocated among the group in accordance with their respective holdings of Class B Units.

Common and subordinated units and interests will be allocated to the Class B Unit holders in the same percentages as those held for the benefit of the Class A Unit holders.

      As a result of the application of these allocation procedures, our executive officers as a group will receive an aggregate of 568,913 common units and 2,030,007 subordinated units in exchange for their Class B Units and will have an economic interest in an aggregate of 57,722 common units and 205,966 subordinated units by virtue of their continued ownership of Class A Units. Please see the table under “Security Ownership of Certain Beneficial Owners and Management” for the numbers of common and subordinated units to be received by each of the named executive officers of Regency GP LLC.

      The formula for allocation of common and subordinated units of Regency Energy Partners LP among the holders of Class A Units and Class B Units of HMTF Regency, L.P. established by the general partner of HMTF Regency, L.P. is predicated on the indicative aggregate market capitalization of Regency Energy Partners LP based on the initial public offering price of common units.

      As a result of distributions of the net proceeds from this offering to the HMTF Investors, certain of our officers will receive, by virtue of their holdings of Class A Units and Class C Units of HMTF Regency, L.P., an aggregate of approximately $3,000,000.

Limited Partner Interests to be Received by Certain Directors

      Robert D. Kincaid and Gary W. Luce, who were elected as directors of Regency Gas Services LLC at the time of its acquisition by HMTF Regency, L.P., were awarded net profits interests in the form of Class D Units in HMTF Regency, L.P. as an incentive to serve as directors. Those Class D Units will be converted into and exchanged for common and subordinated units and general partner interests on the same basis as Class B Units, except that the allocation between Class A Units and Class D Units will be on the basis of 99.6% and 0.4%, respectively. As a result of the application of these allocation procedures, these two directors will together receive an aggregate of 19,842 common units and 70,799 subordinated units in exchange for their Class D Units and will have an economic interest in an aggregate of 13,357 common units and 47,661 subordinated units by virtue of their continued ownership of Class A Units. Please see the table under “Security Ownership of Certain Beneficial Owners and Management” for the numbers of common and subordinated units and general partner interests to be received by each director.

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      As a result of distributions of the net proceeds from this offering to the HMTF Investors, Messrs. Kincaid and Luce will together receive, by virtue of their holdings of Class A Units of HMTF Regency, L.P., an aggregate of approximately $690,000.

General Partner Interests

      The HMTF Investors, our executive officers and Messrs. Kincaid and Luce together will own economic interests in our general partner of 91.6%, 7.9% and 0.5%, respectively, as a result of their ownership of Class A Units, Class B Units and Class D Units in HMTF Regency, L.P.

Related Party Transactions with the HMTF Investors

      On December 1, 2004, the HMTF Investors acquired 100% of the outstanding member interests of Regency Gas Services LLC from Regency Services LLC and became the single member owner of Regency Gas Services LLC. In connection with this acquisition, we entered into a financial advisory agreement and a monitoring and oversight agreement with an affiliate of Hicks Muse. The financial advisory agreement designates an affiliate of Hicks Muse to be our exclusive financial advisor in connection with any subsequent transactions (as such term is defined in the financial advisory agreement). The monitoring and oversight agreement provides that an affiliate of Hicks Muse will provide us with financial oversight and monitoring services. Each agreement has a term of the earlier of 10 years or until Hicks Muse or its successors or affiliates no longer owns securities of Regency Gas Services.

      Upon the completion of the acquisition by the HMTF Investors and pursuant to the financial advisory agreement, an advisory transaction fee of approximately $6 million was paid to the affiliate of Hicks Muse. This amount was included in the purchase price and was allocated to the assets. In addition, Regency Gas Services LLC paid management and financial advisory fees in the amount of approximately $0.8 million to the affiliate of Hicks Muse in the nine months ended September 30, 2005, and less than $0.1 million for the month of December 2004.

      At the closing of this offering and the related formation transactions, we will pay $9.0 million to an affiliate of Hicks Muse as consideration for the termination of the ten-year financial advisory and monitoring and oversight agreements between the affiliate of Hicks Muse and us. These agreements would have required us to pay to the affiliate of Hicks Muse certain management fees and transaction advisory fees in the future, which would decrease our cash available for distribution. We will continue to be obligated to indemnify Hicks Muse, its affiliates, and their respective directors, officers, controlling persons, agents and employees from all claims, liabilities, loses, damages, expenses and fees and disbursements of counsel related to or arising out of or in connection with the services rendered under these agreements and not resulting primarily from bad faith or wilful misconduct.

      After this offering, the HMTF Investors will own 5,353,896 common units and 19,103,896 subordinated units representing a 62.7% limited partner interest in us, as well as the 2.0% general partner interest.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

      Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the HMTF Investors), on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of Regency GP LLC have fiduciary duties to manage Regency GP LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

      Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

      Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•  approved by the conflicts committee of the board of directors of Regency GP LLC, although our general partner is not obligated to seek such approval;

•  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•  fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

      Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of Regency GP LLC. If our general partner does not seek approval from the conflicts committee and the board of directors of Regency GP LLC determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

      Conflicts of interest could arise in the situations described below, among others.

     Our general partner’s affiliates may engage in competition with us.

      Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement, the owners of our general partner, including the HMTF Investors, are not prohibited from engaging in, and are not required to offer us the opportunity to engage in, other businesses or activities, including those that might be in direct competition with us.

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Our general partner is allowed to take into account the interests of parties other than us, such as Hicks Muse and the HMTF Investors, in resolving conflicts of interest.

      Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

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, without the limitations, might constitute breaches of fiduciary duty.

      In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

•  provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;

•  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Regency GP LLC and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the board of directors of Regency GP LLC in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” Regency GP LLC may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders.

      The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•  the amount and timing of asset purchases and sales;

•  cash expenditures;

•  borrowings;

•  the issuance of additional units; and

•  the creation, reduction or increase of reserves in any quarter.

      In addition, our general partner may use an amount included in this definition of “operating surplus” initially equal to $20.0 million, that would not otherwise constitute operating surplus in order to permit the

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payment of cash distributions on the subordinated units or incentive distribution rights. Please read “How We Make Cash Distributions.”

Our general partner determines which costs incurred by it or Regency GP LLC are reimbursable by us.

      We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

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 partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner does not intend to charge us a management fee. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, are or will be the result of arm’s-length negotiations.

      Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

      Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

      Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

      Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

      Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

      The attorneys, independent accountants and others who have performed services for us regarding the offering have been retained by our general partner. Attorneys, independent accountants and others who will perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

      Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

      Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State-law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a

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	general partner for violations of its fiduciary duties to the limited partners.
Partnership agreement modified standards	Our partnership agreement contains provisions pursuant to which limited partners waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
	In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that the partnership that is our general partner, as well as its general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner, its general partner or the officers and directors of the partner acted in bad faith or engaged in fraud, willful misconduct.
	Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of our general partner must be:
	• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

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      Each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

      We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

      The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

      Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

•  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•  special charges for services requested by a common unitholder; and

•  other similar fees or charges.

      There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

      Resignation or Removal. The transfer agent may resign by notice to us or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

      By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

•  represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

•  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

•  gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

      A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

      We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

      Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

      Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

      The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of these agreements upon request at no charge.

      We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•  with regard to distributions of available cash, please read “Cash Distribution Policy and Restrictions on Distributions” and “How We Make Cash Distributions”;

•  with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

•  with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

•  with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

      Our partnership was organized in September 2005 and will have a perpetual existence.

Purpose

      Our purpose under the partnership agreement is to engage in any business activities that are approved by our general partner. Our general partner, however, may not cause us to engage in any business activities that it determines would cause us to be treated as a corporation for federal income tax purposes. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

      Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney, among other things, to execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to grant consents and waivers on behalf of the limited partners under, our partnership agreement.

Capital Contributions

      Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Voting Rights

      The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

•  during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

•  after the subordination period, the approval of a majority of the common units.

      In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

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Issuance of additional units	No approval right.
Amendment of the partnership agreement	Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “— Termination and Dissolution.”
Reconstitution of our partnership upon dissolution	Unit majority. Please read “— Termination and Dissolution.”
Withdrawal of the general partner	Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2015 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”
Removal of the general partner	Not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest	Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2015. See “— Transfer of General Partner Interest.”
Transfer of incentive distribution rights	Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2015. Please read “— Transfer of Incentive Distribution Rights.”
Transfer of ownership interests in our general partner	No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

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Limited Liability

      Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•  to remove or replace the general partner;

•  to approve some amendments to the partnership agreement; or

•  to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

      Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

      Our subsidiaries conduct business in five states. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.

      Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our membership interest in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Issuance of Additional Securities

      Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

      It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

      In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities that may effectively rank senior to the common units.

      Upon issuance of additional partnership securities, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

      General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. Our general partner, however, will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

      Prohibited Amendments. No amendment may be made that would:

•  enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

•  enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

      The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can only be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 64.0% of our outstanding limited partner units.

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      No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

•  a change in our name, the location of our principal place of our business, our registered agent or our registered office;

•  the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

•  a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating company nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•  an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

•  an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;

•  any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

•  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

•  any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

•  a change in our fiscal year or taxable year and related changes;

•  mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance; or

•  any other amendments substantially similar to any of the matters described in the clauses above.

      In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or transferee in connection with a merger or consolidation approved in connection with our partnership agreement, or if our general partner determines that those amendments:

•  do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

•  are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

•  are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

•  are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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•  are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

      Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

      In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

      A merger or consolidation of us requires the prior consent of our general partner. Our general partner, however, will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

      In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, the transaction would not result in a material amendment to the partnership agreement, and each of our units will be an identical unit of our partnership following the transaction.

      If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination and Dissolution

      We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

•  the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

•  there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

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•  the entry of a decree of judicial dissolution of our partnership; or

•  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

      Upon a dissolution under the last clause above, the holders of a unit majority, may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in our partnership agreement by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•  the action would not result in the loss of limited liability of any limited partner; and

•  neither our partnership, the reconstituted limited partnership, our operating company nor any of our other subsidiaries, would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

      Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as provided in “How We Make Cash Distributions — Distributions of Cash upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

      Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2015 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2015, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”

      Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

      Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 33¹/3% of the outstanding units by our general partner and its

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affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own 64.0% of the total of our outstanding limited partner units.

      Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

•  the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

      In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

      If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

      In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

      Except for transfer by our general partner of all, but not less than all, of its general partner interest in our partnership to:

•  an affiliate of our general partner (other than an individual); or

•  another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in our partnership to another person prior to December 31, 2015 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our

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general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

      Our general partner and its affiliates may at any time, transfer subordinated units or units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

      At any time, the HMTF Investors may sell or transfer all or part of their membership interest in Regency GP LLC to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

      Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest of the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to December 31, 2015, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2015, the incentive distribution rights will be freely transferable.

Change of Management Provisions

      Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of our general partner.

      Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

•  the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

      If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected

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by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

•  the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

•  the current market price as of the date three days before the date the notice is mailed.

      As a result of our general partner’s right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Meetings; Voting

      Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or transferees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. In the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

      Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

      Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

      Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

      By the transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited

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Liability”, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

      If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

      Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•  our general partner;

•  any departing general partner;

•  any person who is or was an affiliate of a general partner or any departing general partner;

•  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

•  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

•  any person designated by our general partner.

      Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

      Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates and include amounts paid pursuant to indemnification obligations of our general partner or its general partner. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

      Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and financial reporting purposes, our fiscal year is the calendar year.

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      We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

      We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

      Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

•  a current list of the name and last known address of each partner;

•  a copy of our tax returns;

•  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

•  copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

•  information regarding the status of our business and financial condition; and

•  any other information regarding our affairs as is just and reasonable.

      Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

      Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

      After the sale of the common units offered hereby, management of our general partner, and the HMTF Investors and their affiliates will hold an aggregate of 5,353,896 common units and 19,103,896 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

      The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•  1% of the total number of the securities outstanding; or

•  the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

      Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least one year, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

      The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

      Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

      The HMTF Investors, our partnership, our operating company, our general partner and the directors and executive officers of Regency GP LLC, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

      This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to the general partner and us, as to all material tax matters and all legal conclusions insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Regency Energy Partners LP and our operating company.

      The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

      All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are, to the extent noted herein, based on the accuracy of the representations made by us.

      No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which 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. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

      For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

      A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

      Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income

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Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

      No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins, L.L.P. that, based upon the Internal Revenue Code, applicable regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and the operating company will be disregarded as an entity separate from us for federal income tax purposes.

      In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

      (a) Neither we nor the operating company will elect to be treated as a corporation; and

      (b) For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

      If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

      If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

      The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

      Unitholders who have become limited partners of Regency Energy Partners LP will be treated as partners of Regency Energy Partners LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise

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of all substantive rights attendant to the ownership of their common units will be treated as partners of Regency Energy Partners LP for federal income tax purposes.

      A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

      Income, gain, deductions or losses would not be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Regency Energy Partners LP.

      The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Regency Energy Partners LP for federal income tax purposes.

Tax Consequences of Unit Ownership

      Flow-Through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

      Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

      A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

      Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2008, will be allocated an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2008, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and

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anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

      Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

      Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

      In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

      The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

      A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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      Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

•  interest on indebtedness properly allocable to property held for investment;

•  our interest expense attributed to portfolio income; and

•  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

      The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

      Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

      Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

      Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as is needed to eliminate the negative balance as quickly as possible.

      An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given

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effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect.

      Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees”, allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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

•  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

•  any cash distributions received by the unitholder as to those units would be fully taxable; and

•  all of these distributions would appear to be ordinary income.

      Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where 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 units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

      Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

      Tax Rates. In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.

      Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

      Where the remedial allocation method is adopted (and we will adopt it), Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement,

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the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Uniformity of Units.”

      Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.”

      A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

      The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

      Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

      Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair

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market value of our assets and their tax basis immediately prior to this offering will be borne by the general partner and its affiliates. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

      To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

      If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

      The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

      Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

      Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

      Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

      Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both

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ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

      The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

      Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•  a short sale;

•  an offsetting notional principal contract; or

•  a futures or forward contract with respect to the partnership interest or substantially identical property.

      Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

      Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

      The use of this method may not be permitted under existing Treasury Regulations as there is no controlling authority on the issue. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders although Vinson & Elkins L.L.P. is of the opinion that this method is a reasonable method. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

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      A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

      Notification Requirements. A purchaser of units who purchases units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

      Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

      Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

      We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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Tax-Exempt Organizations and Other Investors

      Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

      Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

      Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

      In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

      Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

      Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

      The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

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      Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names Regency GP LLC as our Tax Matters Partner.

      The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

      A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

      Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

      (a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

      (b) whether the beneficial owner is:

      1. a person that is not a United States person;

      2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

      3. a tax-exempt entity;

      (c) the amount and description of units held, acquired or transferred for the beneficial owner; and

      (d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

      Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

      Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

      A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable

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year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

      (1) for which there is, or was, “substantial authority”; or

      (2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

      If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for penalties. More stringent rules apply to “tax shelters,” which we do not believe includes us.

      A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

      Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

      Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties,”

•  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and

•  in the case of a listed transaction, an extended statute of limitations.

      We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

      In addition to federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Texas, Louisiana, Kansas, Oklahoma, Arkansas and Colorado, and, except for Texas, each imposes a personal income tax on individuals as well as an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable

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years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

      It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN REGENCY ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

      An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•  whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

•  whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

•  whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

      The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

      Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

      In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

      The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

      (a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

      (b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

      (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

      Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

      Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

      We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC and Lehman Brothers Inc. are the representatives of the underwriters. Subject to the terms and conditions of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:

		Number of
Underwriters		Common Units
UBS Securities LLC			3,781,250
Lehman Brothers Inc.			3,781,250
Citigroup Global Markets Inc.			1,925,000
Wachovia Capital Markets, LLC			1,925,000
A.G. Edwards & Sons, Inc.			1,512,500
KeyBanc Capital Markets, a Division of McDonald Investments Inc.			825,000
	Total		13,750,000

      The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.

      Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:

•  receipt and acceptance of our common units by the underwriters, and

•  the underwriters’ right to reject orders in whole or in part.

      We have been advised by the representatives that the underwriters intend to make a market in our common units, but that they are not obligated to do so and may discontinue making a market at any time without notice.

      In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses electronically.

Option to Purchase Additional Common Units

      We have granted the underwriters an option to buy up to an aggregate 2,062,500 additional common units. This option may be exercised if the underwriters sell more than 13,750,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above.

Commissions and Discounts

      Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $0.73 per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $0.10 per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein, and, as a

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result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms.

      The following table shows the per unit and total underwriting discounts and commissions we will pay to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 2,062,500 units.

	No Exercise		Full Exercise
Per Unit	$	1.2125	$	1.2125
Total	$	16,671,875	$	19,172,656

      We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions and structuring fees, will be approximately $3.0 million.

      In addition, we will pay the representatives a structuring fee of $1,375,000 of the gross proceeds of this offering and any exercise of the underwriters’ option to purchase additional common units for their role in the evaluation, analysis and structuring of our partnership.

No Sales of Similar Securities

      We, our subsidiaries, our general partner and its affiliates, including the executive officers and directors of our general partner, and the participants in our directed unit program have entered into lock-up agreements with the underwriters. Under these agreements, we and each of these persons may not, without the prior written approval of UBS Securities LLC and Lehman Brothers Inc., offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing. These restrictions will be in effect for a period of 180 days after the date of this prospectus. The lock-up period will be extended under certain circumstances where we release, or pre-announce a release of our earnings or announce material news or a material event during the 17 days before or 16 days after the termination of the 180-day period in which case the restrictions described above will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

      At any time and without public notice, UBS Securities LLC and Lehman Brothers Inc. may in their discretion, release all or some of the securities from these lock-up agreements. When determining whether or not to release common units from these restrictions, the primary factors that UBS Securities LLC and Lehman Brothers Inc. will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request. UBS Securities LLC and Lehman Brothers Inc. have no present intent to release any of the securities from these lock-up agreements.

Indemnification

      We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make in respect of those liabilities.

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Directed Unit Program

      At our request, certain of the underwriters have reserved up to 620,000 common units (less than 5.0% of the aggregate common units being offered by this prospectus) for sale at the initial public offering price to the officers, directors and employees of our general partner and its sole member and certain other persons associated with us. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, through a directed unit program. The minimum investment amount for participation in the program is $2,500. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.

      Any participant purchasing in excess of $100,000 worth of reserved common units will be prohibited from offering, selling, contracting to sell or otherwise disposing of the common units for a period of 180 days after the date of this prospectus.

Nasdaq National Market Quotation

      We have been approved to list our common units on the Nasdaq National Market under the trading symbol “RGNC.”

Price Stabilization, Short Positions

      In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:

•  stabilizing transactions;

•  short sales;

•  purchases to cover positions created by short sales;

•  imposition of penalty bids; and

•  syndicate covering transactions.

      Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

      The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.

      Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.

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      The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.

      As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the Nasdaq National Market, in the over-the-counter market or otherwise.

Determination of Offering Price

      Prior to this offering, there has been no public market for our common units. The initial public offering price was determined by negotiation by us and the representatives of the underwriters. The principal factors considered in determining the initial public offering price include:

•  the information set forth in this prospectus and otherwise available to the representatives;

•  our history and prospects, and the history and prospects of the industry in which we compete;

•  our past and present financial performance and an assessment of the directors and officers of our general partner;

•  our prospects for future earnings and cash flow and the present state of our development;

•  the general condition of the securities markets at the time of this offering;

•  the recent market prices of, and demand for, publicly traded common units of generally comparable master limited partnerships; and

•  other factors deemed relevant by the underwriters and us.

Electronic Distribution

      A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

      Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Discretionary Sales

      The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of units offered by them.

Stamp Taxes

      If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

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Affiliations

      The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of their business. In addition, some of the underwriters have engaged in, and may in the future engage in, transactions with us and our predecessor and perform services for us in the ordinary course of their business. In particular, affiliates of UBS Securities LLC, Wachovia Capital Markets, LLC and KeyBanc Capital Markets, a Division of McDonald Investments Inc., are lenders under our second amended and restated credit facility. Additionally, an affiliate of UBS Securities LLC is the counterparty to one of our interest rate swaps.

      Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed ten percent. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on the Nasdaq National Market or a national securities exchange.

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VALIDITY OF THE COMMON UNITS

      The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas, and for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

      The consolidated financial statements as of December 31, 2004 and Regency LLC Predecessor’s statement as of December 31, 2003, and for the period from acquisition date (December 1, 2004) to December 31, 2004, and the Regency LLC Predecessor’s statements for the period from January 1, 2004 to November 30, 2004 and for the period from inception (April 2, 2003) to December 31, 2003, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

      The balance sheets as of September 14, 2005, for Regency Energy Partners LP and Regency GP LP included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

      We have filed with the SEC a registration statement on Form S-1 (No. 333-129332) regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

      We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

FORWARD-LOOKING STATEMENTS

      Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “forecast,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

178

INDEX TO CONSOLIDATED FINANCIAL INFORMATION

Regency Energy Partners LP
Unaudited Pro Forma Condensed Financial Statements		F-2
	Introduction	F-2
Unaudited Pro Forma Condensed Consolidated Balance Sheet at September 30, 2005		F-3
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2004		F-4
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2005		F-5
Notes to Unaudited Pro Forma Condensed Financial Statements		F-6
Regency Gas Services LLC
Report of Independent Registered Public Accounting Firm		F-10
Consolidated Balance Sheets		F-11
Consolidated Statements of Operations		F-12
Consolidated Statements of Changes in Member Interest		F-13
Consolidated Statements of Cash Flows		F-14
Notes to Consolidated Financial Statements		F-15
Regency Energy Partners LP
Report of Independent Registered Public Accounting Firm		F-37
Balance Sheet as of September  14, 2005		F-38
Note to Balance Sheet		F-39
Regency GP LP
Report of Independent Registered Public Accounting Firm		F-40
Balance Sheet as of September  14, 2005		F-41
Note to Balance Sheet		F-42

F-1

REGENCY ENERGY PARTNERS LP

UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS

Introduction

      The unaudited pro forma condensed financial statements are presented for Regency Energy Partners LP which was formed on September 8, 2005, and is the successor to Regency Gas Services LLC. As Regency Energy Partners LP was recently formed, the historical financial statements are the same as Regency Gas Services LLC. In connection with this offering and the formation of Regency Energy Partners LP, Regency Gas Services LLC will be converted into a limited partnership to serve as the operating partnership.

      The following unaudited pro forma condensed consolidated balance sheet as of September 30, 2005 is presented to illustrate the estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds” as if this offering had occurred on September 30, 2005. No adjustment was required for the acquisition of the west Texas assets from Duke Energy Field Services LP (Duke) or the HMTF Investor’s acquisition of Regency Gas Services LLC because they occurred prior to September 30, 2005 and therefore are already reflected in the historical September 30, 2005 consolidated balance sheet.

      The following unaudited pro forma condensed combined statements of operations for the year ended December 31, 2004 are presented to illustrate the estimated effects as if the following events had occurred on January 1, 2004:

•  The purchase of the west Texas assets from Duke on March 1, 2004,

•  The HMTF Investor’s acquisition which occurred on December 1, 2004 in which they purchased the Regency LLC Predecessor and “pushed down” the new asset basis in the Predecessor at the time of acquisition,

•  The estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds,” and

•  The estimated effect on interest expense from the November 30, 2005 amendment to our credit facility.

      The unaudited pro forma condensed consolidated statement of operations for the nine months ended September 30, 2005 is presented to illustrate the estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds.” The estimated effect on interest expense from the November 30, 2005 amendment to our credit facility is included as a pro forma adjustment as well. There was no adjustment required for the acquisition of the west Texas assets from Duke or the HMTF Investor’s acquisition for the nine months ended September 30, 2005 since the results of these transactions are already included in the historical consolidated financial statements.

      The unaudited pro forma condensed financial statements are based on the audited Regency Gas Services LLC consolidated financial statements, included elsewhere in this prospectus, as adjusted to illustrate the estimated pro forma effects of the transactions described above. The unaudited pro forma condensed financial statements should be read together with “Selected Historical and Selected Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Regency Gas Services LLC consolidated financial statements and the notes to those statements included elsewhere in this prospectus.

      The unaudited pro forma condensed financial statements are based on assumptions that Regency Energy Partners LP believes are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results.

F-2

Regency Energy Partners LP

Unaudited Pro Forma Condensed Consolidated Balance Sheet

September 30, 2005

								Regency
			Regency Gas					Energy
			Services LLC					Partners LP
					Adjustments			Pro Forma
			Historical		for Offering			As Adjusted
			($ thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	14,080	$	(37,500	)(a)	$	24,580
						275,000	(b)
						(18,047	)(c)
						(9,000	)(d)
						(196,953	)(e)
						(3,000	)(f)
	Restricted cash			5,502		—			5,502
	Accounts receivable, net of allowance of $135 at September 30, 2005			84,289		(10,500	)(a)		73,789
	Assets from risk management activities			1,106		—			1,106
	Other current assets			4,324		—			4,324
Total current assets				109,301		—			109,301
Property, plant and equipment, net				404,446		—			404,446
Intangible and other assets
	Intangible assets, net of amortization			16,838		—			16,838
	Goodwill			57,552		—			57,552
	Long-term assets from risk management activities			1,321		—			1,321
	Other, net of amortization on debt issuance costs of $1,998 at September 30, 2005			9,053		—			9,053
Other assets				84,764		—			84,764
TOTAL ASSETS			$	598,511	$	—		$	598,511
LIABILITIES & PARTNERS’ EQUITY
Current Liabilities:
	Accounts payable and accrued liabilities		$	95,045	$	—		$	95,045
	Escrow payable			5,502		—			5,502
	Accrued taxes payable			2,672		—			2,672
	Interest payable			81		—			81
	Liabilities from risk management activities			18,284		—			18,284
	Current portion of long term debt			2,600		—			2,600
	Other current liabilities			436		—			436
Total current liabilities				124,620		—			124,620
Long-term liabilities from risk management activities				10,961		—			10,961
Long-term debt				305,750		—			305,750
Member Interest				157,180		(48,000	)(a)		—
						275,000	(b)
						(18,047	)(c)
						(9,000	)(d)
						(196,953	)(e)
						(3,000	)(f)
						(157,180	)(g)
Partners’ Equity
	Limited partner interests
		Common units		—		77,018	(g)		77,018
		Subordinated units		—		77,018	(g)		77,018
	General partner interest			—		3,144	(g)		3,144
Total partners’ equity				157,180		—			157,180
TOTAL LIABILITIES AND PARTNERS’ EQUITY			$	598,511	$	—		$	598,511

See accompanying notes to unaudited pro forma condensed financial statements.

F-3

Regency Energy Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2004

								Adjustments									Regency
		Combined						for Amended									Energy
		Historical			Adjustments			Credit Facility						Adjustments			Partners LP
		December 31,			for Asset			and						for the			Pro Forma As
		2004(1)			Purchase(2)			Acquisition(3)			Pro Forma			Offering			Adjusted
		($ thousands, except per unit data)
TOTAL REVENUE		$	480,162		$	21,733	(h)	$	—		$	501,895		$	—		$	501,895
EXPENSE
Total cost of sales			403,748			17,910	(h)		—			421,658			—			421,658
Operating expenses			19,605			1,342	(h)		—			20,947			—			20,947
General and administrative			7,209			409	(h)		—			7,618			2,124	(o)		9,742
Transaction expenses			7,003			—			(7,003	)(k)		—			—			—
Depreciation and amortization			11,742			621	(i)		7,951	(l)		20,314			—			20,314
	Total operating expense		449,307			20,282			948			470,537			2,124			472,661
OPERATING INCOME (LOSS)			30,855			1,451			(948	)		31,358			(2,124	)		29,234
OTHER INCOME AND DEDUCTIONS
Interest expense, net			(6,432	)		(312	)(j)		(5,324	)(m)		(9,193	)		—			(9,193	)
									2,875	(p)
Loss on debt refinancing			(3,022	)		—			3,022	(n)		—			—			—
Other income and deductions, net			200			—			—			200			—			200
	Total other income and deductions		(9,254	)		(312	)		573			(8,993	)		—			(8,993	)
INCOME FROM CONTINUING OPERATIONS (LOSS)		$	21,601		$	1,139		$	(375	)	$	22,365		$	(2,124	)	$	20,241
General partners’ interest in income from continuing operations																	$	405
LIMITED PARTNERS’ INTEREST IN INCOME FROM CONTINUING OPERATIONS																	$	19,836
Net income per limited partner unit (basic and diluted)																	$	0.52
Weighted average limited partner units outstanding:
	Basic																	38,207,792
	Diluted																	38,253,834

(1)	Represents eleven months of historical activity of Regency LLC Predecessor for the period from January 1, 2004 through November 30, 2004, and one month of historical activity of Regency Gas Services LLC for the period from the date of acquisition, December 1, 2004, through December 31, 2004 on a combined basis.
(2)	Adjustments in this column relate to the purchase of our west Texas assets, which we purchased March 1, 2004. Accordingly, these adjustments reflect two months of activity.
(3)	Adjustments in this column relate to the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004. These adjustments were calculated as if the transaction occurred on January 1, 2004, net of the effects of the west Texas asset purchase described in note (2) above. This column also includes the effect of the November 30, 2005 Amendment to the Credit Facility.

See accompanying notes to unaudited pro forma condensed financial statements.

F-4

Regency Energy Partners LP

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the Nine Months Ended September 30, 2005

												Regency
												Energy
												Partners LP
			Regency Gas
			Services LLC			Adjustments			Adjustments
						for Amended			for the			Pro Forma
			Historical			Credit Facility			Offering			As Adjusted
			($ thousands, except per unit data)
REVENUE(1)			$	434,566		$	—		$	—		$	434,566
EXPENSE
Cost of sales				386,892			—			—			386,892
Operating expenses				15,495			—			—			15,495
General and administrative				9,571			—			1,043	(o)		10,614
Depreciation and amortization				15,718			—			—			15,718
		Total operating expense		427,676			—			1,043			428,719
OPERATING INCOME				6,890			—			(1,043	)		5,847
OTHER INCOME AND DEDUCTIONS
Interest expense, net				(12,684	)		2,156	(p)		—			(10,528	)
Loss on debt refinancing				(7,724	)		—			—			(7,724	)
Other income and deductions, net				226			—			—			226
		Total other income and deductions		(20,182	)		2,156			—			(18,026	)
NET LOSS FROM CONTINUING OPERATIONS			$	(13,292	)	$	2,156		$	(1,043	)	$	(12,179	)
General partners’ interest in net loss from continuing operations												$	(244	)
LIMITED PARTNERS’ INTEREST IN NET LOSS FROM CONTINUING OPERATIONS												$	(11,935	)
Net loss per limited partner unit (basic and diluted)												$	(0.31	)
Weighted average limited partner units outstanding:
	Basic												38,207,792
	Diluted												38,253,834

(1)  Includes $12.7 million of unrealized losses on hedging transactions.

See accompanying notes to unaudited pro forma condensed financial statements.

F-5

Regency Energy Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements

1. Basis of Presentation, Transactions and the Offering

      The historical financial information is derived from the audited historical financial statements of Regency Gas Services LLC. Immediately prior to the offering Regency Gas Services LLC will be converted to a limited partnership and serve as the operating partnership. For the unaudited pro forma condensed consolidated balance sheet as of September 30, 2005, the pro forma adjustments have been prepared as if this offering and the related transactions had taken place on September 30, 2005. For the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2004 and the unaudited pro forma condensed consolidated statement of operations for the nine months ended September 30, 2005, the pro forma adjustments have been prepared as if the offering and the related transactions had taken place on January 1, 2004. A general description of the transactions and adjustments for the offering affecting the unaudited pro forma condensed financial statements follows:

•  in the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2004, the purchase of the west Texas assets on March 1, 2004 required adjustment to include the first two months of 2004 in order to present a full year of information on these assets as if they were acquired on January 1, 2004;

•  in the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2004, the acquisition of Regency Gas Services LLC by the HMTF Investors on December 1, 2004 required adjustment to reflect purchase accounting and interest as if the transaction occurred on January 1, 2004;

•  in the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2004 and nine months ended September 30, 2005, an adjustment for the estimated effect on interest expense from the November 30, 2005 amendment to our credit facility;

•  adjustments for the offering include the following: (1) the distribution of cash, cash equivalents and accounts receivable to the HMTF Investors immediately prior to the consummation of the offering, (2) the sale of 13,750,000 common units at a price of $20 per unit, (3) payment of underwriting discounts, fees, and transaction expenses, (4) payment of $9.0 million to an affiliate of Hicks Muse as consideration to terminate financial advisory, monitoring and oversight agreements, (5) the distribution of $197.0 million to the HMTF Investors for reimbursement of capital expenditures resulting from the acquisition of Regency Gas Services LLC by the HMTF Investors, (6) the payment of $3.0 million for offering and formation expenses, and (7) the elimination of the remaining members interest converted into general and limited partner interests. No adjustment has been made for borrowings under the revolving portion of our second amended and restated credit facility incurred temporarily to finance working capital, which are expected to be repaid with proceeds of the offering.

2. Pro Forma Adjustments and Assumptions

      (a) Reflects distribution of cash and cash equivalents and accounts receivable to the HMTF Investors immediately prior to the consummation of this offering in the amounts of $37.5 million and $10.5 million, respectively.

      (b) Reflects the sale of 13,750,000 common units at a price of $20.00 per unit amounting to total proceeds of $275.0 million.

      (c) Reflects underwriting discounts and structuring fee of $16.7 million and $1.3 million, respectively, paid out of proceeds.

      (d) Reflects payment in the amount of $9.0 million to an affiliate of Hicks Muse as consideration for the termination of financial advisory and monitoring and oversight agreements. A similar adjustment was

F-6

Regency Energy Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements — (Continued)

not made to the pro forma statements of operations as the adjustment is non-recurring in nature. The actual adjustment will be included in the statement of operations once the offering is complete.

      (e) Reflects the distribution of $197.0 million to the HMTF Investors for reimbursement of their capital expenditures resulting from the acquisition of Regency Gas Services LLC by the HMTF Investors.

      (f) Reflects the payment of $3.0 million of expenses associated with the offering and related formation transactions.

      (g) Reflects the elimination of $157.2 million of member interest converted into general and limited partner interests. The limited partner interests consist of common units representing 49% ownership and subordinated units representing 49% ownership and the general partner interest representing 2% ownership.

      (h) In the Adjustments for Asset Purchase column, the revenues, cost of sales, operating expenses and general and administrative expenses represent two months of historical activity from the west Texas assets.

      (i) The west Texas assets were recorded at fair value on March 1, 2004 in accordance with purchase accounting with $67.3 million being allocated to property, plant and equipment, including acquisition costs, with a weighted average useful life of 18 years, and $1.0 million being allocated to current liabilities. The monthly depreciation expense is $0.3 million, for a two-month total of $0.6 million.

      (j) In connection with the purchase or the west Texas assets, the Company incurred additional term debt of $45.4 million. In calculating the interest expense for January and February 2004, the Company used the January 2004 three-month LIBOR plus the appropriate margin from the credit facility in place at that time. Application of the total rate of 4.13% as the incremental debt yields a two month interest expense of $0.3 million. We did not include any amortization of additional debt issuance costs due to the March 1, 2004 amendment to the credit agreement since the balance of debt issuance costs was expensed in connection with the new credit facility at the time of the HMTF transaction.

      (k) Represents the reversal of non-recurring expenses incurred by the Regency LLC Predecessor directly related to the HMTF Transaction. These expenses consisted of compensation, legal and other expenses paid by Regency LLC Predecessor prior to the HMTF acquisition.

      (l) On December 1, 2004, the Company implemented purchase accounting with respect to the acquisition of Regency Gas Services LLC by the HMTF Investors. Accordingly, the Company recorded assets at fair value, which increased the depreciable basis. As a result, the pro forma depreciation and amortization expense increased based on the new fair values and estimated useful lives of the assets. Also contributing to the increase in depreciation and amortization expense was the amortization of identifiable intangible assets, which were not present prior to the acquisition. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

At December 1, 2004

	($ millions)
Current assets	$	66.8
Property, plant and equipment		332.0
Intangibles		18.5
Goodwill		58.5
Total assets acquired		475.8
Current liabilities		(55.8	)
Net assets acquired	$	420.0

F-7

Regency Energy Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements — (Continued)

      The adjustment to depreciation and amortization expense of $8.0 million resulted in pro forma depreciation and amortization expense of $20.3 million, of which $18.4 million represented annual depreciation expense and $1.9 million represented annual amortization expense under the new tangible and intangible asset basis. Property, plant and equipment of $332.0 million has a weighted average useful life of 18 years, which yields annual depreciation of $18.4 million. The identifiable intangible assets of $18 million have a weighted average useful life of 9.5 years, which yields annual amortization of $1.9 million. The adjustment of $8.0 million was determined as follows:

	($ millions)
Reverse historical depreciation and amortization	$	(11.7	)
Reverse two months depreciation from adjustment (i) above		(0.6	)
Annual depreciation calculated on “stepped-up” asset basis		18.4
Annual amortization calculated on identifiable intangible assets		1.9
Net adjustment	$	8.0

      (m) Simultaneously with the acquisition of the Company by the HMTF Investors, the Company paid off its existing debt and incurred new term debt of $250 million under the new credit facility. In calculating the interest expense for the year 2004, the Company used the average of the January, April, July and October 2004 three-month LIBOR plus the appropriate margin from the new credit facility. Application of the total rate of 4.29% to the term debt yields a pro forma annual interest expense of $10.6 million. Also included in this adjustment is the annual amortization of debt issuance costs related to the new credit facility. The debt issuance cost of $7.5 million was amortized using the weighted average remaining life of the loan of 67 months to calculate a pro forma amortization expense of $1.4 million. The net adjustment of $5.3 million to achieve these results was determined as follows:

	($ millions)
Reverse historical interest expense	$	(6.4	)
Reverse two months interest expense from adjustment (j) above		(0.3	)
Annual interest expense on new debt issuance		10.6
Annual debt issuance cost amortization		1.4
Net adjustment	$	5.3

      (n) Represents the reversal of the loss on debt refinancings recorded in connection with the purchase of the West Texas assets on March 1, 2004 and the HMTF Investors’ acquisition of Regency Gas Services LLC on December 1, 2004.

      (o) Represents the elimination of the management fee that is assumed to be terminated effective upon the closing of the offering of $0.3 million and $0.8 million for the year ended December 31, 2004 and nine months ended September 30, 2005, respectively. Additionally, this adjustment includes the compensation expenses related to the long term incentive plan of $2.4 million and $1.8 million for such periods, respectively.

      (p) Represents interest savings from the November 30, 2005 amendment to our credit facility. We increased our first lien credit facility by $50.0 million and used the proceeds to pay off our $50.0 million second lien credit facility effectively lowering the interest rate on that $50.0 million. In addition, we lowered the interest rate on our first lien credit facility by 0.5%. These two changes resulted in annual interest savings of $2.9 million. The interest savings for the nine months ended September 30, 2005 was $2.2 million. The pro forma adjustment does not give effect to certain amounts paid in connection with the amendment of the credit facility of $0.8 million which will be expensed as incurred.

F-8

Regency Energy Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements — (Continued)

3. Pro Forma Net Income (Loss) per Unit

      Pro forma net income (loss) per unit is determined by dividing the pro forma net income (loss) that would have been allocated, in accordance with the net income and loss allocation provisions of the limited partnership agreement, to the holders of common and subordinated units under the two-class method, after deducting the general partner’s interest of 2% in the pro forma net income (loss), by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that (1) the Minimum Quarterly Distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding were 19,103,896 common and 19,103,896 subordinated. The common and subordinated unitholders each represent 49% limited partner interests. All units were assumed to have been outstanding since January 1, 2004. Basic and diluted pro forma net income (loss) per unit is equivalent since there are only an immaterial amount of dilutive units outstanding at the date of closing of the initial public offering of the common units of Regency Energy Partners LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.

F-9

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Regency Gas Services LLC:

      We have audited the accompanying consolidated balance sheets of Regency Gas Services LLC and subsidiaries (the “Company”) as of December 31, 2004 and Regency LLC Predecessor as of December 31, 2003, and the related consolidated statements of operations, changes in member interest, and cash flows for the period from acquisition date (December 1, 2004) to December 31, 2004, and Regency LLC Predecessor for the period from January 1, 2004 to November 30, 2004 and for the period from inception (April 2, 2003) to December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004, and Regency LLC Predecessor as of December 31, 2003, and the results of the Company’s operations and cash flows for the period from acquisition date (December 1, 2004) to December 31, 2004 and the results of Regency LLC Predecessor’s operations and cash flows for the period from January 1, 2004 to November 30, 2004 and the period from inception (April 2, 2003) to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas

September 14, 2005

F-10

Regency Gas Services LLC

Consolidated Balance Sheets

($ in thousands)

			Regency LLC
			Predecessor			Regency Gas Services LLC
			December 31,			December 31,			September 30,
			2003			2004			2005
									(Unaudited)
ASSETS
Current Assets:
	Cash and cash equivalents		$	1,574		$	3,272		$	14,080
	Restricted cash			9,026			5,410			5,502
	Accounts receivable, net of allowance of $0 at December 31, 2003 and $135 at December 31, 2004 and September 30, 2005			31,390			49,215			84,289
	Assets from risk management activities			—			2,767			1,106
	Advances to affiliates			576			—			—
	Other current assets			1,070			2,713			4,324
Total current assets				43,636			63,377			109,301
Property, plant and equipment
	Gas plants and buildings			19,136			44,606			46,613
	Gathering and transmission systems			95,760			250,392			256,781
	Other property, plant and equipment			8,033			20,427			24,879
	Construction-in-progress			382			14,380			91,856
		Total property, plant and equipment		123,311			329,805			420,129
	Less accumulated depreciation			(4,325	)		(1,457	)		(15,683	)
Property, plant and equipment, net				118,986			328,348			404,446
Intangible and other assets
	Intangible assets, net of amortization			—			18,342			16,838
	Goodwill			—			58,529			57,552
	Assets held for sale			—			4,101			—
	Long-term assets from risk management activities			—			6,243			1,321
	Other, net of amortization on debt issuance costs of $333 at December 31, 2003; $112 at December 31, 2004 and $1,998 at September 30, 2005			1,708			7,549			9,053
Total intangible and other assets				1,708			94,764			84,764
TOTAL ASSETS			$	164,330		$	486,489		$	598,511
LIABILITIES & MEMBER INTEREST
Current Liabilities:
	Accounts payable and accrued liabilities		$	27,026		$	51,471		$	95,045
	Escrow payable			9,026			5,410			5,502
	Accrued taxes payable			906			1,460			2,672
	Interest payable			143			—			81
	Distributions payable			69			—			—
	Liabilities from risk management activities			—			14			18,284
	Current portion of long term debt			11,213			2,000			2,600
	Other current liabilities			704			1,170			436
Total current liabilities				49,087			61,525			124,620
Long-term liabilities from risk management activities				—			—			10,961
Long-term debt				55,387			248,000			305,750
Commitments and contingencies
Member interest				59,856			176,964			157,180
TOTAL LIABILITIES AND MEMBER INTEREST			$	164,330		$	486,489		$	598,511

See accompanying notes to consolidated financial statements.

F-11

Regency Gas Services LLC

Consolidated Statements of Operations

($ in thousands)

			Regency LLC						Regency Gas			Regency LLC			Regency Gas
			Predecessor						Services LLC			Predecessor			Services LLC
			Period from						Period from
			Inception			Period from			Acquisition Date
			(April 2, 2003)			January 1, 2004			(December 1, 2004)			Nine Months Ended September 30,
			to December 31,			to November 30,			to December 31,
			2003			2004			2004			2004			2005
												(Unaudited)
REVENUE
Gas sales			$	127,149		$	279,582		$	32,616		$	220,857		$	301,174
NGL sales				46,697			123,827			11,890			95,083			123,263
Gathering, transportation and other fees				9,439			19,016			1,943			15,537			19,703
Unrealized/realized gain/(loss) from risk management activities				—			—			322			—			(19,891	)
Other				3,248			9,896			1,070			7,629			10,317
	Total revenue			186,533			432,321			47,841			339,106			434,566
EXPENSE
Cost of gas and liquids				158,524			352,508			39,979			277,621			380,855
Other cost of sales				4,937			10,254			1,007			8,330			6,037
Operating expenses				7,012			17,786			1,819			13,651			15,495
General and administrative				2,651			6,571			638			5,323			9,571
Transaction expenses				724			7,003			—			—			—
Depreciation and amortization				4,324			10,129			1,613			8,146			15,718
		Total operating expense		178,172			404,251			45,056			313,071			427,676
OPERATING INCOME				8,361			28,070			2,785			26,035			6,890
OTHER INCOME AND DEDUCTIONS
Interest expense, net				(2,392	)		(5,097	)		(1,335	)		(4,139	)		(12,684	)
Loss on debt refinancing				—			(3,022	)		—			(1,406	)		(7,724	)
Other income and deductions, net				205			186			14			67			226
		Total other income and deductions		(2,187	)		(7,933	)		(1,321	)		(5,478	)		(20,182	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS				6,174			20,137			1,464			20,557			(13,292	)
DISCONTINUED OPERATIONS
Income (loss) from operations of Regency Gas Treating LP (including gain on disposal of $626; Note 2)				—			(121	)		—			(14	)		732
NET INCOME (LOSS)			$	6,174		$	20,016		$	1,464		$	20,543		$	(12,560	)

See accompanying notes to consolidated financial statements.

F-12

Regency Gas Services LLC

Consolidated Statements of Changes in Member Interest

For the Periods from Inception (April 2, 2003) to September 30, 2005 (unaudited)

($ in thousands)

						Accumulated
						Other
			Comprehensive			Comprehensive			Member
			Income (loss)			Income (loss)			Interest
Regency LLC Predecessor
	Member Interest contribution June 2, 2003								$	53,750
	Net income for the period from inception (April 2, 2003) to December 31, 2003		$	6,174						6,174
	Member interest distributions									(68	)
	Comprehensive Income			6,174
	Balance, December 31, 2003									59,856
	Member Interest contribution March 1, 2004									10,000
	Net income for the period from January 1, 2004 to November 30, 2004			20,016						20,016
	Comprehensive Income		$	20,016
	Balance, November 30, 2004									89,872
	Member interest distributions									(89,872	)
	Balance, December 1, 2004								$	—
Regency Gas Services LLC
	Net consideration paid by HMTF Investors								$	171,000
	Member Interest contributions December 2004									4,500
	Net income for the period from December 1, 2004 to December 31, 2004		$	1,464						1,464
	Comprehensive Income			1,464
	Balance, December 31, 2004		$	—					$	176,964
	Member contribution July 25, 2005									15,000
	Net loss for the nine months ended September 30, 2005			(12,560	)					(12,560	)
	Other Comprehensive Income (Loss):
		Net change in fair value of cash flow hedges		(25,706	)		(25,706	)
		Amounts realized in earnings during the period		3,482			3,482
	Other Comprehensive Income (Loss)			(22,224	)					(22,224	)
	Comprehensive Income (Loss) (unaudited)		$	(34,784	)
	Balance, September 30, 2005 (unaudited)					$	(22,224	)	$	157,180

See accompanying notes to consolidated financial statements.

F-13

Regency Gas Services LLC

Consolidated Statements of Cash Flows

($ in thousands)

									Regency Gas			Regency LLC			Regency Gas
			Regency LLC Predecessor						Services LLC			Predecessor			Services LLC
			Period from						Period from
			Inception			Period from			Acquisition Date			Nine Months Ended
			(April 2, 2003)			January 1, 2004			(December 1, 2004)			September 30,
			to December 31,			to November 30,			to December 31,
			2003			2004			2004			2004			2005
												(Unaudited)
OPERATING ACTIVITIES
Net income (loss)			$	6,174		$	20,016		$	1,464		$	20,543		$	(12,560	)
Adjustments to reconcile net income (loss) to net cash flows provided (used) by operations:
	Depreciation & amortization			4,658			10,461			1,745			8,425			16,565
	Loss on debt refinancing						3,022						1,406			7,724
	Risk management portfolio valuation changes			—			—			(322	)		34			13,590
	Gain on the sale of Regency Gas Treating LP assets			—			—			—			—			(626	)
	Gain on the sale of NGL line pack			—			—			—			—			(628	)
Cash flows impacted by changes in Current assets and liabilities:
		Accounts receivable		(31,390	)		(20,408	)		2,583			(6,807	)		(35,074	)
		Advances to affiliates		(576	)		576			—			—			—
		Other current assets		(1,070	)		(1,169	)		(2,430	)		(1,876	)		(1,611	)
		Accounts payable and accrued liabilities		26,880			18,122			(155	)		7,400			34,970
		Accrued taxes payable		906			1,475			(921	)		664			1,212
		Interest payable		143			398			(541	)		(143	)		81
		Distributions payable		68			(69	)		—			(69	)		—
		Other current liabilities		706			173			293			(76	)		(734	)
	Other assets			(5	)		(196	)		(6,646	)		—			(1,555	)
Net cash flows provided (used) by operating activities				6,494			32,401			(4,930	)		29,501			21,354
INVESTING ACTIVITIES
	Capital expenditures			(3,624	)		(15,092	)		(2,143	)		(11,522	)		(76,472	)
	Cash outflows for acquisition by HMTF Investors			—			—			(127,804	)		—			(5,808	)
	Proceeds from sale of Regency Gas Treating LP assets			—			—			—			—			6,000
	Proceeds from the sale of NGL line pack			—			—			—			—			1,099
	Restricted cash for enhancement project			—			—			—			—			(6,145	)
	Purchase of El Paso properties			(119,541	)		—			—
	El Paso — escrow adjustment			—			1,168			—			1,168			—
	Cardinal acquisition			—			(3,533	)		—			(3,533	)		—
	Purchase of Waha properties			—			(67,264	)		—			(67,264	)		—
Net cash flows used in investing activities				(123,165	)		(84,721	)		(129,947	)		(81,151	)		(81,326	)
FINANCING ACTIVITIES
	Borrowings under credit facilities			70,000			45,363			250,000			45,363			60,000
	Repayments under credit facilities			(3,401	)		(10,492	)		(101,471	)		(5,943	)		(1,650	)
	Net borrowings under revolving credit facilities			—			13,000			(13,000	)		6,000			—
	Debt issuance costs			(2,036	)		(1,491	)		(7,514	)		(1,540	)		(2,570	)
	Member interest contributions			53,750			10,000			4,500			10,000			15,000
	Member interest distributions			(68	)		—			—			—			—
Net cash flows provided by financing activities				118,245			56,380			132,515			53,880			70,780
Net increase (decrease) in cash and cash equivalents				1,574			4,060			(2,362	)		2,230			10,808
Cash and equivalents at beginning of period				—			1,574			5,634			1,574			3,272
Cash and equivalents at end of period			$	1,574		$	5,634		$	3,272		$	3,804		$	14,080
Supplemental cash flow information:
	interest paid		$	1,883		$	4,437		$	1,763		$	4,123		$	12,224
	Non-cash capital expenditures in accounts payable		$	146		$	804		$	(134	)	$	405		$	14,412

See accompanying notes to consolidated financial statements.

F-14

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004)

1. Organization, Business Operations and Summary of Significant Accounting Policies

      Organization and Business Operations — Regency Gas Services LLC (the Company), a Delaware limited liability company, was formed April 2, 2003 and began operations on June 2, 2003. The Company gathers, processes, transports and markets natural gas and natural gas liquids.

      On December 1, 2004, Regency Acquisition LLC (Regency Acquisition), a wholly owned subsidiary of HMTF Regency LP (the Parent), acquired 100% of the outstanding member interests of the Company from Regency Services LLC (Seller) and became the single member owner of the Company. As the single member owner, Regency Acquisition has the right to manage the business and affairs of the Company and to determine, subject to limitations imposed by credit agreements (see Note 3), the amount of any distributions payable by the Company to the member. Regency Acquisition has no obligation to make any capital contribution to the Company beyond its initial investment. An investment fund organized and controlled by Hicks, Muse, Tate & Furst Incorporated (Hicks Muse) is the principal equity owner of the Parent. This acquisition is referred to as the “HMTF transaction” throughout this document.

      The Parent accounted for its acquisition of the Company as a purchase, and purchase accounting adjustments, including goodwill and other intangible assets, have been “pushed down” and are reflected in the financial statements of the Company and its subsidiaries for the periods subsequent to December 1, 2004. For periods prior to its acquisition, the Company is designated herein as the “Regency LLC Predecessor,” and its consolidated financial statements for periods ended before December 1, 2004 are similarly designated. The comparability of the operating results for the Regency LLC Predecessor and those of the Company for subsequent periods is affected by the purchase accounting adjustments, including amortization of intangible assets. See Note 2 for further discussion of goodwill and intangible assets.

      Basis of Presentation — The accompanying consolidated financial statements include the assets, liabilities and results of operations of the Company and its wholly owned subsidiaries, Regency Intrastate Gas LLC, Regency Midcon Gas LLC, Regency Liquids Pipeline LLC, Regency Gas Gathering and Processing LLC, Gulf States Transmission Corporation, Regency Gas Services Waha LP, Regency NGL Marketing LP, and Regency Gas Treating LP. These subsidiaries are Delaware limited liability companies or limited partnerships except for Gulf States Transmission Corporation, which is a Louisiana corporation. The consolidated financial statements of Regency Gas Services LLC have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. The unaudited consolidated interim financial statements as of and for the nine months ended September 30, 2005 and 2004 have been prepared on the same basis as the annual financial statements and all normal and recurring adjustments have been made and should be read in conjunction with the annual financial statements. The results of operations for an interim period may not give a true indication of results for a full year.

      The Company operates and manages its business as two reportable segments: a) gathering and processing, and b) transportation. (See Note 9).

      Certain amounts in the prior year have been reclassified to conform to current year presentation.

      Use of Estimates — These consolidated financial statements have been prepared in conformity with GAAP which necessarily include the use of estimates and assumptions by management. Actual results could differ from these estimates.

F-15

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Cash and Cash Equivalents — Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

      Property, Plant and Equipment — Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts. Any gain or loss on disposition is included in operating income. The gas required to maintain pipeline minimum pressures is capitalized and classified as property, plant, and equipment. Furthermore, interim financing costs (capitalized interest) associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. There was no capitalized interest in 2004 or in 2003. For the nine months ended September 30, 2005, the Company capitalized $0.9 million of interest expense. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

      The Company assesses long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.

      The Company had no actual or conditional asset retirement obligations under Statement of Financial Accounting Standards (SFAS) No. 143 “Accounting for Asset Retirement Obligations” at September 30, 2005, December 31, 2004 or December 31, 2003.

      Depreciation — Depreciation of plant and equipment is recorded on a straight-line basis over the following estimated useful lives.

Functional Class of Property	Useful Lives
Gathering and Transmission	5 - 20 years
Gas Plants and Buildings	15 - 35 years
General — Land Rights of Way; Computer, Office, and Telecommunications Equipment; and Vehicles	3 - 10 years

Period	Depreciation Expense
	($ in millions)
Inception (April 2, 2003) to December 31, 2003	$	4.3
January 1, 2004 to November 30, 2004		10.1
Acquisition date (December 1, 2004) to December 31, 2004		1.5
Nine months ended September 30, 2004 (unaudited)		8.1
Nine months ended September 30, 2005 (unaudited)		14.3

      Intangible Assets — Following the HMTF transaction, management identified two classes of separately identifiable intangible assets, which will be amortized on a straight line basis over their useful lives. The two classes of intangible assets are (i) permits and licenses and (ii) customer contracts.

      The value of the licenses and permits was determined by discounting the income associated with activities that would be lost over the period required to replace these permits. An intangible asset in the amount of $12.0 million was recognized. The Company recorded $0.6 million of amortization of this intangible asset in the nine months ended September 30, 2005 and $0.1 million for the month of December 2004. The estimated useful life of the asset is fifteen years.

F-16

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Immediately prior to the HMTF transaction, the Regency LLC Predecessor renegotiated a number of significant customer contracts. The value of customer contracts was determined by using a discounted cash flow model associated with the contracts. An intangible asset in the amount of $6.5 million was recognized. Regency recorded $0.8 million of amortization of this intangible asset in the nine months ended September 30, 2005 and $0.1 million in the month of December 2004. The estimated useful life for 67% of the contracts is 12 years, while the remaining 33% have an estimated useful life of three years.

      See Note 2 for more information with respect to intangible assets.

      Goodwill — Following the HMTF transaction, the Company recorded goodwill in the amount of $58.5 million. See Note 2 for more information on this transaction. In accordance with SFAS No. 142 “Goodwill and Other Intangible Assets,” goodwill is not subject to amortization. The Company tests for impairment to determine whether any of the asset value recorded in goodwill should be written off annually on December 31 or more frequently if events or changes in circumstances indicate that an asset might be impaired. The changes in the carrying amount of goodwill from December 31, 2003 to December 31, 2004 and to September 30, 2005 are as follows:

					Regency Gas
	Gathering and				Treating LP
	Processing		Transportation		Discontinued
Goodwill	Segment		Segment		Operations			Total
	($ in millions)
Balance as of December 31, 2003 (Regency LLC Predecessor)	$	—	$	—	$	—		$	—
Goodwill recorded as a result of the HMTF transaction		23.4		34.2		0.9			58.5
Balance as of December 31, 2004		23.4		34.2		0.9			58.5
Goodwill disposed of in sale of Regency Gas Treating LP assets		—		—		(0.9	)		(0.9	)
Balance as of September 30, 2005 (unaudited)	$	23.4	$	34.2	$	—		$	57.6

      Other Assets, net — Other assets, net consist of debt issuance costs, which are capitalized and amortized to expense over the life of the related debt. In addition, the Company has included $6.1 million of restricted cash in Other Assets, net. This restricted cash relates to borrowings under the credit facility which were restricted for use in funding certain enhancement projects as of September 30, 2005. The funds were spent on these projects in October 2005.

      Gas Imbalance Accounting — Pursuant to imbalance agreements, for which settlement prices are not contractually established, quantities of natural gas over-delivered or under-delivered are recorded monthly as receivables or payables using the lower of cost or market for assets, and market prices for liabilities.

F-17

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      The Company had imbalance receivables and payables as set forth in the table below, classified in the financial statements as other current assets and other current liabilities, respectively. These imbalances are settled with deliveries of natural gas.

	Regency LLC
	Predecessor
	December 31, 2003		December 31, 2004		September 30, 2005
					(Unaudited)
	($ in millions)
Imbalance Receivables	$	0.7	$	0.9	$	3.1
Imbalance Payables	$	0.6	$	1.0	$	0.2

      Revenue Recognition — The Company earns revenues from domestic sales of natural gas, natural gas liquids and by providing gathering and transmission services. These sales stem primarily from gas gathering and processing and, secondarily from merchant pipeline transmission services. Revenues associated with these activities are recognized when natural gas products are delivered or at the time services are performed. The Company’s gas purchase contracts are structured so that it earns margins on the resale of natural gas or NGLs reflecting the value added by gathering, processing, or transporting the products. The Company records revenue and cost of sales on the gross basis for those transactions in which the Company acts as principal and takes title to gas that is purchased for resale. Where the Company acts as agent and its customers pay a fee for providing a service such as gathering or transportation, fees are recorded in revenues and disclosed separately from sales of products.

      Risk Management Activities — The Company delivers the NGLs that are an output of its gathering and processing facilities to fractionators. Under the terms of the contracts for fractionating services, the Company receives floating rate prices in exchange for title to the liquids. Because these sales are settled with physical deliveries, these contracts are treated as normal sales and are not marked to market. This arrangement exposes the Company to price volatility and creates the need to manage that risk.

      The Company maintains a commodity risk management program with the objective of managing its exposure to commodity price risk with respect to natural gas liquids. On December 2, 2004, as required by covenants in its credit agreements, the Company entered into certain natural gas liquids swap and crude oil put option contracts. The Company does not enter into derivative contracts for trading purposes.

      In addition, the Company’s $460 million credit facility agreements (see Note 3) expose it to interest rate risk due to the variable nature of the interest rates stated in these credit agreements. The credit agreements required the Company to enter into an interest rate swap with the objective of hedging a portion of its exposure to interest rate risk. See Note 3 for more information on the Company’s interest rate hedging activities.

      Subsequent to the HMTF transaction through June 30, 2005, the Company evaluated the application of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, to determine whether the transactions qualified for hedge accounting. During this period, the Company marked these transactions to market and recorded the unrealized gains and losses in revenue for its commodity contracts and interest expense for the interest rate swap. At December 31, 2004, our determination of the net fair value of the Company’s risk management activities resulted in an asset of $9.0 million.

      Effective July 1, 2005, the Company elected hedge accounting for its ethane, propane, and butane swaps, as well as for its interest rate swap. These contracts are designated as cash flow hedges under SFAS No. 133. Changes in the fair value of contracts for which hedge accounting applies will be recorded in Other Comprehensive Income to the extent the hedges are effective. At September 30, 2005, the

F-18

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

Company’s determination of the net fair value of its risk management activities resulted in a liability of $26.8 million, of which $19.9 million has been recorded as a charge against revenue and $0.2 million has been recorded as a reduction in interest expense, net.

      The Company has not elected hedge accounting for its crude oil put options, which are used to reduce downside price exposure for other heavy natural gas liquids. At the time that these crude oil put options were purchased, there was no liquid market for contracts that would exactly match the forecasted transactions hedged by the crude oil puts. These contracts have been and will continue to be marked to market with unrealized and realized gains or losses on these contracts recorded in revenue.

      The Company continues to enter into NGL swaps, and as of September 30, 2005, the Company has hedged its exposure to commodity price risk for a portion of its forecasted transactions in ethane, propane, butane and natural gasoline through calendar year 2007. As of September 30, 2005, $18.3 million is expected to be reclassified into earnings from Other Comprehensive Income (loss) in the next twelve months.

      Maintenance Costs — Maintenance costs are expensed as incurred.

      Benefits — From inception of the Regency LLC Predecessor through May 31, 2005, the Regency LLC Predecessor and the Company contracted with an independent third party to provide payroll and advisory human resource services while remaining the co-employer of all employees. On June 1, 2005, the Company terminated that contract, becoming the sole employer of all its employees, and engaged a different vendor to provide payroll and supplemental human resource services. Under both arrangements, payroll and payroll related expenses are included within operating and general and administrative expenses. The Company provides a portion of medical, dental, and other healthcare benefits to employees and, commencing on June 1, 2005, a 50% matching contribution for the first 6% of employee contributions to their 401(k) accounts. The amount of matching contributions for the nine months ended September 30, 2005 was not material. The Company has no pension obligations.

      Income Taxes — No provision is made in the accounts for Federal or state income taxes. The Company is not subject to these taxes, all such taxes being passed through to become a liability of the limited partners of the Parent.

      Comprehensive Income — Comprehensive income (loss) is the same as net income (loss) for all periods ending December 31, 2004 and earlier.

      Earnings Per Unit — Earnings per unit has not been presented as the Company is controlled through a single member owner, Hicks Muse.

      Initial Public Offering — On September 15, 2005 Regency Energy Partners LP filed a Registration Statement on Form S-1 under the Securities Exchange Act of 1933 with the SEC (File No. 333-128332) in connection with the Company’s expected initial public offering (“IPO”). In connection with the IPO, the Company had incurred costs totaling $1.4 million as of September 30, 2005, and has included those costs in the September 30, 2005 consolidated balance sheet within Other Assets.

2. Acquisitions and Dispositions

Acquisition of Regency Gas Services LLC by the HMTF Investors

      On December 1, 2004, Regency Acquisition, a wholly owned subsidiary of the Parent, acquired 100% of the membership interest of the Company (the HMTF transaction).

F-19

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      The HMTF transaction was effected pursuant to a Purchase and Sale Agreement (PSA) dated October 21, 2004 among Regency Acquisition, as the purchaser, and, among others, Regency Services LLC, the owner of the member interests in the Predecessor, as the seller. The aggregate purchase price was $420 million, including transaction costs of $8 million. The purchase price was funded primarily through $243 million of term loans (net of issuance costs) to the Company and $171 million of equity investments by the Parent. Pursuant to the PSA, a liability in the amount of $5.8 million was recorded at December 31, 2004 to reflect a post-closing adjustment to the purchase price primarily for working capital adjustments. The Company paid this amount in February 2005.

      The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	At
	December 1,
	2004
	($ in millions)
Current assets	$	66.8
Property, plant and equipment		332.0
Intangibles		18.5
Goodwill		58.5
Total assets acquired		475.8
Current liabilities		(55.8	)
Net assets acquired	$	420.0

      All of the separately identified intangibles listed below were valued using a discounted cash flow methodology and are amortized using the straight-line method with no residual value.

							Regency Gas
	Permits and			Customer			Treating LP
	Licenses			Contracts			Permits		Total
	($ in millions)
Useful life (in years)		15			3 - 12			n/a
Gross carrying amount at December 1, 2004	$	11.9		$	6.5		$	0.1	$	18.5
Accumulated amortization at December 31, 2004		(0.1	)		(0.1	)		0.0		(0.2	)
Net carrying amount at December 31, 2004		11.8			6.4			0.1		18.3
Accumulated amortization at September 30, 2005 (unaudited)		(0.7	)		(0.9	)		—		(1.6	)
Net carrying amount at September 30, 2005 (unaudited)	$	11.2		$	5.6		$	—	$	16.8
Amortization for the nine months ended September 30, 2005 (unaudited)	$	0.6		$	0.8		$	—	$	1.4

F-20

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      The expected amortization of the intangible assets is given below.

For the year ending December 31,	Total
	($ in millions)
2005	$	1.9
2006		1.9
2007		1.8
2008		1.2
2009		1.2

      As part of the PSA, $12.5 million of the purchase price was transferred to an escrow account. The restricted cash asset and associated escrow liability are recorded on the balance sheet of Regency Acquisition (not included in these consolidated financial statements). According to the terms of the PSA and the escrow agreement, Regency Acquisition is indemnified to the extent of the amount in escrow against any losses associated with a breach by the Seller of its representations or warranties, any environmental costs or liabilities incurred as a result of circumstances on or before the closing date, and any losses incurred as a result of Gulf States Transmission Corporation’s noncompliance with specified FERC regulations. A deductible of $4.0 million applies. The escrow agreement expires on May 30, 2006. In August 2005, the Parent released approximately $1.3 million of the amount held in escrow to the Seller. Any settlement paid to Regency Acquisition will result in a change in the purchase price, which could result in adjustments in the purchase price allocation.

Regency Gas Treating LP (Cardinal)

      On April 1, 2004, the Regency LLC Predecessor completed the purchase of gas processing and treating assets located in Louisiana and Texas from Cardinal Gas Services LLC for $3.5 million of cash. The value of assumed liabilities was immaterial. Subsequent to the purchase, the assets were contributed to a new subsidiary operating as Regency Gas Treating LP. These assets consisted of Joule-Thompson and refrigeration gas processing equipment, amine gas treating equipment and contracts to provide processing and treating services. The equipment removes impurities and natural gas liquids from natural gas, resulting in the natural gas meeting standards required by transmission pipeline operators. After the acquisition, additional capacity was added. See Note 7 for additional information on this Regency LLC Predecessor related party transaction.

F-21

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Soon after the acquisition by the Parent, the Company determined that these assets were not core to its operations and classified these assets as held for sale on the balance sheet at December 31, 2004. On May 2, 2005, the Company sold the assets of Regency Gas Treating for $6.0 million. After the allocation of $0.9 million of goodwill, the resulting gain was $0.6 million. The Company has treated Cardinal as a discontinued operation, the results of which are shown below:

	Regency LLC			Period from
	Predecessor			Acquisition		Regency LLC
	Period from			Date		Predecessor
	January 1,			(December 1,		Nine Months		Nine Months
	2004 to			2004) to		Ended		Ended
	November 30,			December 31,		September 30,		September 30,
	2004			2004		2004		2005
						(Unaudited)
	($ in millions)
Equipment lease revenue	$	0.5		$	0.1	$	0.3	$	0.3
Operating income (loss)		0.1			—		—		0.1
Net income (loss)		(0.1	)		—		—		0.7
Gain on disposal								$	0.6

Waha

      On March 1, 2004, the Regency LLC Predecessor completed the purchase of gathering, processing, and treating assets in west Texas from Duke Energy Field Services LP (Duke) for $67.3 million of cash and $1.0 million in assumed liabilities, including transaction costs. The facilities, known as the Waha system, consist of more than 750 miles of pipeline, 42,000 horsepower of compression, and gas processing and treating capacities of 125 MMcf/d. The assets are owned and operated by Regency Gas Services Waha, LP, a wholly owned subsidiary of the Company. The purchase accounting method resulted in an allocation of the total purchase price to property, plant and equipment with no goodwill or intangible assets.

      The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	At March 1, 2004
	($ in millions)
Current assets	$	—
Property, plant and equipment		67.3
Total assets acquired		67.3
Current liabilities		(1.0	)
Net assets acquired	$	66.3

      The following unaudited pro forma financial information has been prepared as if the acquisition of the west Texas assets had occurred at the beginning of each period presented. The pro forma amounts include certain adjustments to historical results of operations including depreciation and amortization expense (based upon the estimated fair values and useful lives of property, plant and equipment).

F-22

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Such unaudited pro forma information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Company is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future. While the Company’s inception date is April 2, 2003, the pro forma results are related to only the seven months of operations ended December 31, 2003.

	Regency LLC Predecessor
	Period from
	Inception		Period from		Nine Months
	(April 2, 2003) to		January 1, 2004 to		Ended
	December 31, 2003		November 30, 2004		September 30, 2004
	($ in millions)
Revenue	$	262.6	$	454.1	$	361.2
Net Income		10.0		21.1		21.6

      See Note 6 for a description of commitments and contingencies related to the Waha system.

Mid-Continent and North Louisiana

      On June 2, 2003, the Regency LLC Predecessor completed an asset purchase from El Paso for the mid-continent and north Louisiana assets. These assets consist of four gas processing plants, approximately 2,400 miles of natural gas gathering and transmission pipeline, and 70,000 horsepower of compression capacity. The total purchase price was $119.5 million, including transaction closing costs. The purchase accounting method resulted in an allocation of the total purchase price to property, plant and equipment with no goodwill or intangible assets.

      The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	At June 2, 2003
	($ in millions)
Current assets	$	—
Property, plant and equipment		119.5
Total assets acquired		119.5
Current liabilities		—
Net assets acquired	$	119.5

      At the purchase closing date, $9.0 million of the purchase price was deposited into an escrow account as a condition of the PSA. Under the terms of the escrow agreement, certain amounts are eligible for release at various points of time following the closing date. At September 30, 2005, $5.5 million of this amount remains in escrow. See Note 6 for more information related to this escrow account.

F-23

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

3. Long-Term Debt

      Obligations under the Company’s credit facilities at December 31, 2003, December 31, 2004 and September 30, 2005 are as follows:

		Regency LLC
		Predecessor
		December 31, 2003			December 31, 2004			September 30, 2005
								(unaudited)
		($ in millions)
Term Loans		$	66.6		$	250.0		$	308.4
Revolving Loans			—			—			—
	Less: Current Portion		(11.2	)		(2.0	)		(2.6	)
Long-term Debt		$	55.4		$	248.0		$	305.8
Total Facility Limit		$	80.0		$	290.0		$	458.4
	Term Loans		(66.6	)		(250.0	)		(308.4	)
	Revolving Loans		—			—			—
	Letters of Credit		(0.6	)		—			(18.1	)
Credit Available		$	12.8		$	40.0		$	131.9

      In July 2005, the Company amended its credit agreement, increasing the available term loans to $309 million from $249 million, increasing the available revolving loans to $150 million from $40 million, and available letters of credit to $30 million from $20 million. Letters of credit, to the extent issued, reduce the amount available for revolving loans. Interest will be charged at the London Inter-Bank Offer Rate (LIBOR) or the Alternate Base Rate (ABR) (equivalent to the US prime lending rate) plus an applicable margin, which is equivalent to the rates charged prior to this amendment. In connection with the amendments of the credit agreement, the Parent contributed $15 million of additional equity, which the Company received on July 25, 2005. Upon closing of the amended credit agreements, the Company borrowed an additional $25 million of term loans (bringing the outstanding total to $274 million of term loans). The outstanding revolver debt of $10 million was repaid, consistent with the refinancing plan, which included the above mentioned equity infusion and the additional term loan. In September 2005 the Company borrowed the remaining $35 million against the term loan commitments. The quarterly principal payment schedule was amended to require 0.25% of the original principal of any additional term loans in addition to the $0.5 million quarterly principal payments associated with the original term loans. The term loans were originally issued as $260 million of first lien debt and $50 million of second lien debt. The rate paid on the second lien term notes is 3.25% greater than the rate paid on the first lien term notes. The term loans mature in two tranches, with principal repayments of $246.7 million due on June 1, 2010 and $50 million due on December 1, 2010. Commitments for the revolving credit facility expire on July 26, 2010.

      Loans under the credit agreements bear interest on the outstanding balances of term debt and revolver debt at either LIBOR plus margin or at the ABR plus margin, or a combination of both. The weighted average LIBOR Rate plus margin for the two term loan facilities was 6.43% for the nine months ended September 30, 2005. The effective ABR Rate for the revolving loans for the period was 7.98%. A commitment fee on the undrawn revolver balance was charged at an annual rate of 0.50%.

      The weighted average effective rate for the term loans and revolving loans was 6.16% for the nine months ended September 30, 2005.

F-24

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Covenants within the credit agreement required the Company to maintain interest rate protection on at least one-half of its outstanding debt for a minimum of two years. In January 2005, the Company entered into an interest rate swap contract, effectively fixing the interest rate on $125 million of the term loan borrowings at 6.47% for a period of two years. Following the July 2005 amendment of its credit facilities, the Company entered into additional interest rate swaps that effectively fix the interest rate on $200 million of LIBOR based term loans at 6.70% through March 2007 and at 7.36% through March 2009.

      The following table summarizes the Company’s interest rate swap contracts.

	Notional								Total
	Amount		Fixed			Applicable			Fixed
Period Covered	($ millions)		Pay			Margin			Rate
April 2005 to March 2007	$	125.0		3.715	%		2.750	%		6.465	%
August 2005 to March 2007		75.0		4.340			2.750			7.090
April 2007 to March 2009		200.0		4.610			2.750			7.360

      If letters of credit are issued, fees are paid on the outstanding letter of credit balance at the rate of 2.88% or lower if the Company’s credit quality improved.

      The scheduled principal repayments under the credit facility which will become due through the end of the facility term are:

Year Ended	Scheduled Payments as		Scheduled Payments as
December 31,	of December 31, 2004		of September 30, 2005
			(unaudited)
	($ in millions)
2005	$	2.0	$	0.6
2006		2.0		2.6
2007		2.0		2.6
2008		2.0		2.6
2009		2.0		2.6
2010	$	240.0	$	297.4

      Except as summarized above, the terms of the amended credit agreements are the same as those for the $290 million credit facilities described below.

      In accordance with EITF 96-19 “Debtor’s Accounting for a Modification or Exchange of Debt Instrument”, the Company treated the amendments as an extinguishment and reissuance of debt, thereby recognizing a loss in the nine months ended September 30, 2005 on such transaction due to the expensing of approximately $7.7 million (consisting of $5.8 million of unamortized debt issuance costs and $1.9 million paid in July 2005 in connection with the credit facility amendment).

      As of December 31, 2004 and September 30, 2005, the Company had $250 million and $308.4 million in term loans outstanding under the term loan, respectively. During the nine months ended September 30, 2005, the Company borrowed and repaid a total of $33 million against the revolving credit facility. Substantially all of the Company’s assets are pledged as collateral under the credit agreements. Covenants within the credit agreements require the Company to maintain total leverage ratios, interest coverage ratios, and annual capital expenditures within stated limits.

      Please see Note 10 for a description of further amendments to the Company’s credit agreements occurring in November 2005.

F-25

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      On December 1, 2004, the Company replaced the Regency LLC Predecessor’s existing credit facility with a $290.0 million facility. The terms of the former credit facilities are described below.

$290 Million Credit Facility

      At December 31, 2004, the Company had two credit facilities with an aggregate capacity of $290 million. The maturity date for $240 million of this capacity is June 1, 2010, and the remaining $50 million matures on December 1, 2010. Under the agreements, the Company had a $40 million revolving credit facility and a $250 million term loan facility. Up to $20 million of letters of credit were permitted to be issued against the revolving credit facility. Under certain conditions, additional term loans were permitted in an amount not in excess of $40 million in the aggregate. As of December 31, 2004, the Company had $250 million in term loans outstanding under the term loan facility. Substantially all of the Company’s assets were pledged as collateral under the credit agreements. Covenants within the credit agreements required the Company to maintain total leverage ratios, interest coverage ratios, and annual capital expenditures within stated limits.

      The credit facilities restricted payment of dividends to Regency Acquisition and the Parent, but allowed for the reimbursement of tax, legal, accounting, and filing costs incurred by those entities with certain limitations. No such distributions were made. If the Company issued debt or equity securities, the agreements required a repayment of amounts borrowed equal to 100% of the net cash proceeds of an issuance of debt securities and 50% of the net cash proceeds of an issuance of equity securities. After December 31, 2005, payments of principal in addition to scheduled principal payments were required if the Company met certain excess cash flows tests.

$140.0 Million Credit Facility (terminated on December 1, 2004)

      In May 2003 the Regency LLC Predecessor entered into a credit facility under which the lenders provided a $10 million revolving credit facility and a $70 million term loan facility for the principal purpose of financing the Company’s acquisition of the mid-continent and north Louisiana assets. The maturity date was December 31, 2006. The revolving credit facility had a $1.0 million sublimit for the issuance of letters of credit. The $10 million revolving credit facility was subject to a borrowing base limit. The borrowing base limit was the lesser of the sum of 80% of eligible receivables and 50% of eligible inventory or the aggregate amount of the revolving loan commitment. Substantially all of the Regency LLC Predecessor’s assets were pledged as collateral under the credit agreement. Under the credit agreement, the Regency LLC Predecessor was required to maintain current ratios, total leverage ratios, fixed charge coverage ratios, tangible net worth, annual lease obligations and annual capital expenditures within stated limits.

      The credit agreement restricted payment of interest and dividends on securities held by its then parent. A distribution of less than $0.1 million was paid for the reimbursement of taxes in January 2004.

      The outstanding balances of term loans and revolving loans under this credit agreement bore interest at LIBOR plus margin; Base Rate, comprised of U.S. rates, plus margin; or a combination of both. The weighted average effective rate for the term loans and revolving loans was 4.89% for the nine months ended September 30, 2004. Fees were paid on the outstanding letter of credit balance at the LIBOR Rate margin and a fronting fee of ¹/8 of 1%. Commitment fees on undrawn revolver balances were charged at an annual rate of 0.50%.

      On March 1, 2004, the Regency LLC Predecessor amended the credit facility discussed above. Under the amended agreement, the lenders provided a $30 million revolving credit facility and a $110 million

F-26

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

term loan facility for the principal purpose of financing the Company’s acquisition of the Waha system. The revolving credit facility had a $15 million sublimit for the issuance of letters of credit. The maturity date was December 31, 2008. The terms of the amended credit facility were similar to those in the credit facility existing at December 31, 2003 with a few exceptions, including a requirement that the Regency LLC Predecessor, by June 1, 2004 enter into agreements to fix the interest cost on at least 50% of the outstanding term loans for a period of two years. Simultaneously with the March 1, 2004 amendment, the Regency LLC Predecessor expensed $1.4 million of debt issuance costs in accordance with EITF 96-19 “Debtor’s Accounting for a Modification or Exchange of Debt Instrument.”

      On December 1, 2004, in connection with the HMTF transaction, the Regency LLC Predecessor terminated this credit facility and a $55 million notional interest rate swap contract. The outstanding debt of $101 million of term loans and $13 million of revolving loans were repaid concurrently. The remaining debt issuance costs of $1.6 million were expensed in November 2004 in connection with the December 1, 2004 transaction.

4. Fair Value of Financial Instruments

      The estimated fair value of the Company’s financial instruments was determined using available market information and valuation methodologies. The carrying amount of the Company’s cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. The Company’s restricted cash and related escrow payable approximate fair value due to the relatively short-term settlement period of the escrow payable. The Company’s risk management assets and liabilities are carried at market value. The Company’s long-term debt was comprised of borrowings under credit facilities, which at, December 31, 2003, December 31, 2004 and September 30, 2005 accrued interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value for the amount outstanding under the credit facility.

5. Leases

      The Company leases office space and certain equipment for various periods. Management expects that in the normal course of business, office space leases will be renewed or replaced by other leases. The Company has determined that its leases are classified as operating leases. The following table is a schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2004.

For the Year Ended December 31,	Amount
	($ in millions)
2005	$	0.4
2006		0.4
2007		0.4
2008		0.3
Total Minimum Lease Payments	$	1.5

      Total rent expense for operating leases (primarily compressor rentals), including those leases with terms of less than one year, was $1.1 million in the nine months ended September 30, 2005 and $1.6 million and $0.6 million in 2004 and 2003, respectively.

F-27

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Regency Gas Treating (which is reported as a discontinued operation) was the lessor on certain operating leases of gas processing and gas treating equipment. These leases were not material to the Company’s business activities. See Note 2.

6. Commitments and Contingencies

      Legal — The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on the Company’s business, financial condition or results of operations.

      North Louisiana Intrastate Pipeline Enhancement Project (the Enhancement Project) — The Company is currently engaged in a major expansion and extension of its north Louisiana pipeline, for which it expects to spend $140 million excluding charges for capitalized interest. As of September 30, 2005, $65.6 million of this amount had been spent or accrued. The pipeline will have a capacity of 800 MMcf/d and is expected to be completed by the end of 2005. The Company has entered into contracts for engineering services, pipeline construction, and materials procurement as necessary to support the project. In addition, customer contracts for fixed and interruptible transportation have been executed which account for approximately one third of the pipeline’s capacity.

      Escrow Payable — At September 30, 2005, $5.5 million remained in escrow pending the completion by El Paso Field Services, LP (El Paso) of environmental remediation projects pursuant to the purchase and sale agreement (El Paso PSA) related to the Company’s assets in north Louisiana and in the mid-continent area. In the El Paso PSA, El Paso indemnified the Regency LLC Predecessor against losses arising from pre-closing and known environmental liabilities subject to a limit of $84 million and subject to certain deductible limits. Upon completion of a Phase II environmental study, the Regency LLC Predecessor notified El Paso of remediation obligations amounting to $1.8 million with respect to known environmental matters and $3.6 million with respect to pre-closing environmental liabilities. Upon satisfactory completion of the remediation by El Paso, the amount held in escrow will be released. These contractual rights of the Regency LLC Predecessor were continued by the Company unaffected by the HMTF transaction.

      Environmental — Waha Phase I. A Phase I environmental study was performed on the Waha assets by an environmental consultant engaged by the Regency LLC Predecessor in connection with the pre-acquisition due diligence process in 2004. The study noted that most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The study estimated potential environmental remediation costs at specific locations at $1.9 million to $3.1 million. One premise of the study was that the responsibility for remediation of the matters included in the study rests with those previous owners or operators that are engaged in remediation activities relating to those matters. No governmental agency has required that the Company undertakes these remediation efforts. The Company believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Company acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term with a $10 million limit subject to certain deductibles.

      TCEQ Notice of Enforcement. In August 2005, the Company received a Notice of Enforcement or NOE from the Texas Commission on Environmental Quality, or TCEQ. The NOE alleges that, as a result of a number of physical or operational changes made at the Waha gas plant in 2001 before it was acquired by the Regency LLC Predecessor, the plant was operating a source of air emissions without obtaining a required Prevention of Significant Deterioration, or PSD, air permit. This claim appears to be identical to

F-28

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

the claim in an earlier (and now superseded) notice of enforcement sent to the Company in November 2004. The August 2005 NOE contains claims not included in the earlier NOE, however, and alleges that the same changes that triggered the PSD permit requirement also triggered additional requirements under federal standards applicable to new or modified sources of emissions at on-shore natural gas processing plants (NSPS). It also alleges that the Company submitted two incomplete semi-annual deviation reports pursuant to its federal operating permit for this facility.

      After receiving the November 2004 NOE and without admitting any of the allegations in that NOE, the Company submitted a state air permit application to authorize the 2001 changes that allegedly were made at the plant but that would avoid the need for a PSD permit by reducing any emission increases associated with the earlier changes. The TCEQ has issued a construction permit, requiring the completion of an acid gas reinjection well by the end of February 2007. The estimated capital expenditure for the construction of this well is $3.5 million.

      The Company has requested an enforcement review meeting with TCEQ to discuss the allegations in the NOE. Based on the Company’s current understanding of the TCEQ’s allegations, it disagrees with the factual and legal bases for most of the allegations in the NOE. The TCEQ recently proposed an agreed order to resolve the matters contained in the NOE which includes a provision for a fine in an amount up to $30,625. The Company has scheduled a meeting with the staff of the TCEQ in order to negotiate the previsions of the proposed order, which should not have any materially adverse effect on the Company’s consolidated results of operations.

      ODEQ Notice of Violation — In March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent Regency a notice of violation, alleging that the Company is operating the Mocane processing plant in Beaver County, Oklahoma in violation of the National Emission Standard for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities, or NESHAP, and the requirements to apply for and obtain a federal operating permit (also called a Title V permit). The basis for ODEQ’s allegations in the notice of violation is the claim that the hazardous air pollutant emissions from the Mocane processing plant should be aggregated with the hazardous air pollutant emissions from an adjacent plant operated by an unaffiliated company for purposes of determining if the Mocane processing plant is a major source of hazardous air pollutant emissions that is subject to these standards or the requirement to obtain a federal operating permit. The Company is investigating the allegations in the notice of violation, but at this time it believes that the basis for the allegations identified in the notice of violation is inapplicable to the Mocane processing plant and the adjacent plant. There have been no further written communications with the ODEQ concerning the notice of violation. The Company has received an indication that the ODEQ is requesting a determination from the United States Environmental Protection Agency in a similar case that may affect the validity of the allegations in the notice of violation. If the allegations in the notice of violation ultimately prove to be valid, the Company could be required to pay a penalty and implement additional controls at the Mocane processing plant, primarily in the form of a more stringent leak detection and repair program and periodic compliance reporting under a new operating permit. The Company is currently reviewing its legal rights under the PSA to determine what opportunities it might have to recover any claims from the Sellers. The Company cannot predict the outcome of this environmental matter.

      Customers — In January 2005, one of the Company’s customers filed for Chapter 11 reorganization under U.S. bankruptcy law. The customer operates a merchant power plant, for which the Company provides firm transportation of natural gas. Under the contract the customer is obligated to make fixed payments in the amount of approximately $3.2 million per year. The contract expires in mid-2012 and is secured by a $10 million letter of credit. Through November 18, 2005, the customer was current in its

F-29

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

payment obligations. The customer has accepted the firm transportation contract in bankruptcy and extended the letter of credit to April 2006. The letter of credit has an annual renewal provision. The customer’s plan of reorganization has been confirmed by the bankruptcy court, and the customer has since emerged from the protection of the bankruptcy court.

      Employment Agreements — Two members of senior management of the Company are party to employment contracts, and a third has a severance agreement. The employment agreements provide for base salaries and severance payments in certain circumstances and prohibit each person from competing with the Company or its affiliates for a certain period of time following termination.

      Regulatory Environment — In August 2005, Congress enacted and the President signed the Energy Policy Act of 2005. With respect to the oil and gas industry, the new legislation focuses on the exploration and production sector, interstate pipelines, and refinery facilities. In many cases, the Act requires action by various government agencies over the near to mid-term. The Company is unable to determine what impact, if any, the Act will have on its operations and cash flows.

      Hurricane Katrina and Hurricane Rita — Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of the Company’s assets in the region.

      While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to the Company’s facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area. As a result of these disruptions, the Company temporarily curtailed certain of our producers in the west Texas region for approximately four days and operated its north Louisiana processing assets in a reduced recovery mode for approximately six days. The Company does not expect ongoing effects from these temporary disruptions and neither hurricane altered the expected year end 2005 completion date for the Regency Intrastate Enhancement Project.

7. Related Party Transactions

Prior to the HMTF transaction

      On April 1, 2004, the Regency LLC Predecessor acquired Cardinal Gas Services LLC (now classified as a discontinued operation), a gas treating and processing business, for total cash consideration of $3.5 million. Three former executive officers of the Regency LLC Predecessor owned a portion of the equity interest in Cardinal Gas Services LLC. The acquisition was recorded using the purchase accounting method. There was no goodwill associated with this purchase. See Note 2 for more information on this transaction.

      The Regency LLC Predecessor paid $0.2 million in management fees in 2004 and 2003 for corporate development and administrative services to Charlesbank Capital Partners LLC, an affiliate of the Regency LLC Predecessor prior to the HMTF transaction.

      In 2003, the Regency LLC Predecessor incurred $0.6 million of acquisition expenses on behalf of the Regency Services LLC, the Regency LLC Predecessor’s Parent, which is included in advances to affiliates at December 31, 2003. These advances were settled prior to the closing of the HMTF transaction.

      The Regency LLC Predecessor had consulting contracts in place with two former directors. The contracts have been terminated and the amounts paid under these contracts in 2004 and 2003 were not material to the Regency LLC Predecessor’s results of operations.

F-30

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      The equity interests of the members of Regency Services LLC, some of whom were formerly directors of the Regency LLC Predecessor, were sold as a result of the HMTF transaction.

Subsequent to the HMTF transaction

      Upon the completion of the HMTF transaction, an advisory transaction fee of $6.0 million was paid to Hicks, Muse & Co. Partners, L.P., an affiliate of Hicks Muse, by Regency Acquisition LLC. This amount is included in the purchase price and was allocated to the assets.

      The Company paid management and financial advisory fees in the amount of $0.8 million to Hicks Muse in the nine months ended September 30, 2005, and less than $0.1 million for the month of December 2004.

      In connection with the amendment and restatement of the Company’s credit agreement, Regency Acquisition contributed an additional $15 million of equity, which the Company received on July 25, 2005.

8. Concentration Risk

      The following table provides information about the extent of the Company’s reliance on its major customers. Total revenues from transactions with single external customers amounting to 10% or more of the Company’s revenues are disclosed below, together with the identity of the segment reporting the revenues.

						Regency Gas		Regency LLC		Regency Gas
		Regency LLC Predecessor				Services LLC		Predecessor		Services LLC
						Period from
						Acquisition
		Period from		Period from		Date
		Inception		January 1,		(December 1,		Nine Months		Nine Months
		(April 2, 2003)		2004 to		2004) to		Ended		Ended
	Reporting	to December 31,		November 30,		December 31,		September 30,		September 30,
Customer	Segment	2003		2004		2004		2004		2005
								(Unaudited)
		($ in millions)
Alabama Gas Corporation	Transportation	$	22.5	$	69.7	$	11.1	$	53.9	$	78.3
CenterPoint Energy	Transportation		*		*		*		12.9		*
Koch Hydrocarbon, LP	Gathering and Processing		27.6		*		7.1		*		44.1
Atmos Energy Marketing, LLC	Gathering and Processing		*		*		5.8		25.1		39.8
BP Energy Company	Gathering and Processing		*		*		*		24.6		*
Energy Transfer Company	Gathering and Processing		*		*		*		*		*
Exxon Mobil Corp.	Gathering and Processing										34.9

*  Amounts are less than 10% of total Company revenues for the respective periods.

F-31

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      Five of the customers in the table above have credit ratings of BBB or better, and the other two are not rated.

      The following table provides information about the extent of the Company’s reliance on its major gas suppliers. Total cost of gas from transactions with single external customers amounting to 10 percent or more of the Company’s gas purchases are disclosed below, together with the identity of the segment reporting the purchases.

						Regency Gas		Regency LLC		Regency Gas
		Regency LLC Predecessor				Services LLC		Predecessor		Services LLC
						Period from
						Acquisition
		Period from		Period from		Date
		Inception		January 1,		(December 1,		Nine Months		Nine Months
		(April 2, 2003)		2004 to		2004) to		Ended		Ended
	Reporting	to December 31,		November 30,		December 31,		September 30,		September 30,
Supplier	Segment	2003		2004		2004		2004		2005
								(Unaudited)
		($ in millions)
Cohort Energy Company	Transportation	$	28.6	$	55.0	$	6.8	$	43.7	$	58.9
KCS Energy, Inc.	Transportation		19.5		*		*		19.3		31.6
Chesapeake Energy Corporation	Transportation		*		*		3.8		*		40.2

*  Amounts are less than 10% of the total Company gas purchases for the respective periods.

      The Company is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

9. Segment Information

      The Company has two reportable segments: i) gathering and processing and ii) transportation. Gathering and processing involves the collection of raw natural gas from producer wells and transporting it to a treating plant where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas then goes through further processing to remove the natural gas liquids. The treated and processed natural gas then is transported to market, separately from the natural gas liquids. The Company’s gathering and processing segment also includes its natural gas and NGL marketing business. Through the natural gas and NGL marketing business, the Company markets the pipeline quality gas and the NGLs that are produced by its processing plants for its own account and for the accounts of its customers.

F-32

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

      The transportation segment uses pipelines to move natural gas from processing plants to interconnections with larger pipelines or to trading hubs. The Company performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The Company also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets. The north Louisiana intrastate pipeline operated by this segment serves the Company’s gathering and processing facilities in the same area, which create the intersegment revenues shown in the table below.

      Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operating expense. Segment margin is defined as total revenues, including service fees, less cost of gas and liquids and other costs of sales. The Company believes segment margin is an important measure because it is directly related to volumes and commodity price changes. Operating expenses are a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of the Company’s operating expenses. These expenses are largely independent of the volume throughput but fluctuate depending on the activities performed during a specific period. The Company does not deduct operating expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. Results for each income statement period, together with amounts related to balance sheets for each segment, are shown below.

Regency Gas Services LLC

Segment Information

		Gathering and									Consolidated
		Processing		Transportation		Corporate		Eliminations			Total
		($ in millions)
External Revenue
	For the nine months ended September 30, 2005 (unaudited)	$	309.9	$	124.7	$	—	$	—		$	434.6
	For the nine months ended September 30, 2004 (unaudited)*		244.6		94.5		—		—			339.1
	For the one month ended December 31, 2004		35.0		12.8		—		—			47.8
	For the eleven months ended November 30, 2004*		317.6		114.7		—		—			432.3
	For the seven months ended December 31, 2003*		113.4		73.1		—		—			186.5
Intersegment Revenue
	For the nine months ended September 30, 2005 (unaudited)	$	—	$	31.6	$	—	$	(31.6	)	$	—
	For the nine months ended September 30, 2004 (unaudited)*		—		7.4		—		(7.4	)		—
	For the one month ended December 31, 2004		—		3.4		—		(3.4	)		—
	For the eleven months ended November 30, 2004*		—		15.2		—		(15.2	)		—
	For the seven months ended December 31, 2003*		—		0.6		—		(0.6	)		—

F-33

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

		Gathering and									Consolidated
		Processing			Transportation		Corporate		Eliminations		Total
		($ in millions)
Cost of Sales
	For the nine months ended September  30, 2005 (unaudited)	$	272.4		$	114.5	$	—	$	—	$	386.9
	For the nine months ended September 30, 2004 (unaudited)*		198.3			87.7		—		—		286.0
	For the one month ended December 31, 2004		28.8			12.2		—		—		41.0
	For the eleven months ended November 30, 2004*		256.2			106.5		—		—		362.7
	For the seven months ended December 31, 2003*		94.5			68.9		—		—		163.4
Segment Margin
	For the nine months ended September 30, 2005 (unaudited)	$	37.6	(1)	$	10.1	$	—	$	—	$	47.7
	For the nine months ended September 30, 2004 (unaudited)*		46.2			6.9		—		—		53.1
	For the one month ended December 31, 2004		6.2			0.6		—		—		6.8
	For the eleven months ended November 30, 2004*		61.4			8.2		—		—		69.6
	For the seven months ended December 31, 2003*		18.9			4.2		—		—		23.1
Operating Expenses
	For the nine months ended September 30, 2005 (unaudited)	$	14.2		$	1.3	$	—	$	—	$	15.5
	For the nine months ended September 30, 2004 (unaudited)*		12.5			1.2		—		—		13.7
	For the one month ended December 31, 2004		1.6			0.2		—		—		1.8
	For the eleven months ended November 30, 2004*		16.2			1.6		—		—		17.8
	For the seven months ended December 31, 2003*		6.1			0.9		—		—		7.0
Depreciation and Amortization
	For the nine months ended September 30, 2005 (unaudited)	$	12.4		$	2.9	$	0.4		—		15.7
	For the nine months ended September 30, 2004 (unaudited)*		6.5			1.1		0.5		—		8.1
	For the one month ended December 31, 2004		1.3			0.3		—		—		1.6
	For the eleven months ended November 30, 2004*		8.1			1.4		0.6		—		10.1
	For the seven months ended December 31, 2003*		3.2			0.9		0.2		—		4.3
Assets
	September 30, 2005 (unaudited)	$	349.9		$	219.2	$	29.4	$	—	$	598.5
	December 31, 2004		337.1			125.2		24.2		—		486.5
	December 31, 2003*		109.4			39.1		15.8		—		164.3
Liabilities
	September 30, 2005 (unaudited)	$	191.1		$	130.2	$	120.0	$	—	$	441.3
	December 31, 2004		209.7			86.2		13.6		—		309.5
	December 31, 2003*		65.1			25.8		13.6		—		104.5

F-34

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

		Gathering and								Consolidated
		Processing		Transportation		Corporate		Eliminations		Total
		($ in millions)
Expenditures for Long-Lived Assets
	For the nine months ended September 30, 2005 (unaudited)	$	5.9	$	84.4	$	0.6	$	—	$	90.9
	For the nine months ended September 30, 2004 (unaudited)*		70.8		5.8		5.0		—		81.6
	For the one month ended December 31, 2004		nm		nm		nm		nm		nm
	For the eleven months ended November 30, 2004*		73.2		7.5		4.8		—		85.5
	For the seven months ended December 31, 2003*		93.2		28.3		1.8		—		123.3

nm = not meaningful — excludes the HMTF Transaction

*	Regency LLC Predecessor
(1)	Includes $12.7 million of net unrealized losses on risk management activities.

      The table below provides a reconciliation of total segment margin to income (loss) from continuing operations.

Reconciliation of Total Segment Margin to Income (loss) from Continuing Operations

								Regency Gas			Regency LLC			Regency Gas
		Regency LLC Predecessor						Services LLC			Predecessor			Services LLC
		Period from			Period from			Period from
		Inception			January 1,			Acquisition Date			Nine Months Ended
		(April 2, 2003) to			2004 to			(December 1, 2004)			September 30,
		December 31,			November 30,			to December 31,
		2003			2004			2004			2004			2005
											(Unaudited)
		($ in millions)
Total Segment Margin (from above)		$	23.1		$	69.6		$	6.8		$	53.1		$	47.7	(1)
Operating expenses			7.0			17.8			1.8			13.7			15.5
General and administrative			2.7			6.6			0.6			5.3			9.6
Transaction expenses			0.7			7.0			—			—			—
Depreciation and amortization			4.3			10.1			1.6			8.1			15.7
OPERATING INCOME			8.4			28.1			2.8			26.0			6.9
OTHER INCOME AND DEDUCTIONS
Interest expense, net			(2.4	)		(5.1	)		(1.3	)		(4.1	)		(12.7	)
Loss on debt refinancing			—			(3.0	)		—			(1.4	)		(7.7	)
Other income and deductions, net			0.2			0.1			—			—			0.2
	Total other income and deductions		(2.2	)		(8.0	)		(1.3	)		(5.5	)		(20.2	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		$	6.2		$	20.1		$	1.5		$	20.5		$	(13.3	)

(1)  Includes $12.7 million of net unrealized losses on risk management activities.

F-35

Regency Gas Services LLC

Notes to Consolidated Financial Statements

(Unaudited as to balances as of and for the nine month periods

ended September 30, 2005 and 2004) — (Continued)

10. Subsequent Events (unaudited)

      On November 30, 2005, the Company amended its credit facilities, increasing the first-lien term loan commitments by $50 million from $258.4 million to $308.4 million, immediately borrowing this amount and using the proceeds to terminate and repay in full the higher cost $50 million second-lien credit facility. In addition, the interest rate applied to the resulting first-lien loan balance, as well as the rate charged for letters of credit, was reduced by 0.5%. Revolving-debt commitments increased to $160 million from $150 million, and the amount available for letters of credit increased to $50 million from $30 million. Scheduled repayments of principal will be deferred until the term loan maturity date of June 1, 2010.

      Upon the completion of the Company’s IPO, further amendments will take effect that will enable distributions to master limited partnership unit holders; covenants requiring the payment of excess cash flows to reduce principal will cease; and covenants related to coverage ratios will be changed to less restrictive terms than those currently existing.

      In accordance with EITF 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instrument,” the Company expects to record a charge of $0.8 million in the fourth quarter of 2005 related to the extinguishment of its $50 million second-lien credit facility.

      On December 12, 2005, the compensation committee of the board of directors approved a long-term incentive plan (LTIP) for the Company’s employees, subject to the successful completion of the Company’s IPO. The plan grants a total of 340,000 restricted common units and 652,300 common unit options. In the aggregate, these awards represent 992,300 potential common units. Employees receiving LTIP awards will achieve vesting by completing a three-year service period. For each year completed, one-third of the award will vest.

      The Company will make distributions to non-vested restricted common units on a 1:1 ratio with the per unit distributions paid to common units. Upon the vesting of the restricted common units and the exercise of the common unit options, the Company intends to settle these obligations with common units. Accordingly, the Company will recognize an aggregate of $7.2 million of compensation expense related to the grants under LTIP, or $2.4 million for each of the three years of the vesting period for such grants, following the completion of its initial public offering.

      In addition, senior members of management and outside directors who hold Class A, Class B or Class D units of HMTF Regency, L.P. will enter into exchange agreements in connection with the consummation of our initial public offering whereby they will exchange their Class A, Class B or Class D units for common and subordinated units in Regency Energy Partners LP and an interest in Regency GP LLC.

      The Company has evaluated the impact of the exchange agreements and does not expect to record a material amount of compensation expense related to this exchange.

F-36

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Regency GP LP, as general partner of Regency Energy Partners LP:

      We have audited the accompanying balance sheet of Regency Energy Partners LP (the “Partnership”) as of September 14, 2005. The balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the balance sheet based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

      In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of September 14, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas

September 14, 2005

F-37

Regency Energy Partners LP

Balance Sheet as of September 14, 2005

	September 14,
	2005
Assets
Cash	$	1,000
Total assets		1,000
Partners’ Equity
Limited partner’s equity		980
General partner’s equity		20
Total partners’ equity	$	1,000

F-38

Regency Energy Partners LP

Note to Balance Sheet

September 14, 2005

      Regency Energy Partners LP (the “Partnership”), is a Delaware limited partnership formed on September 8, 2005, to acquire all of the member interests of Regency Gas Services LLC. The Partnership is engaged in gathering, processing, marketing, and transporting natural gas and natural gas liquids. The Partnership’s general partner is Regency GP LP.

      The Partnership intends to offer common units, representing limited partner interests, in a public offering. In addition, the Partnership will issue common units and subordinated units, representing additional limited partner interests to Regency Acquisition LLC as well as a 2% general partner interest in the Partnership to Regency GP LP.

F-39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Regency GP LLC, as general partner of Regency GP LP:

      We have audited the accompanying balance sheet of Regency GP LP (the “Partnership”) as of September 14, 2005. The balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the balance sheet based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

      In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of September 14, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas

September 14, 2005

F-40

Regency GP LP

Balance Sheet as of September 14, 2005

	September 14,
	2005
Assets
Cash	$	980.00
Investment in Regency Energy Partners LP		20.00
Total assets	$	1,000.00
Partners’ equity
Limited Partner’s equity	$	999.99
General Partner’s equity		0.01
Total partners’ equity	$	1,000.00

F-41

Regency GP LP

Note to Balance Sheet

September 14, 2005

      Regency GP LP (the “General Partner”) is a Delaware limited partnership formed on September 8, 2005, to become the General Partner of Regency Energy Partners LP. The General Partner is an indirect wholly owned subsidiary of Regency Acquisition LLC. The General Partner owns a 2% general partner interest in Regency Energy Partners LP.

      Regency Energy Partners LP (the “Partnership”), is a Delaware limited partnership formed on September 8, 2005, to acquire all of the member interests of Regency Gas Services LLC. The Partnership is engaged in gathering, processing, marketing, and transporting natural gas and natural gas liquids.

      The Partnership intends to offer common units, representing limited partner interests, in a public offering. In addition, the Partnership will issue common units and subordinated units, representing additional limited partner interests to Regency Acquisition LLC as well as a 2% general partner interest in the Partnership to the General Partner.

F-42

APPENDIX A

AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

REGENCY ENERGY PARTNERS LP

TABLE OF CONTENTS

ARTICLE I. DEFINITIONS
Section 1.1.	Definitions	A-1
Section 1.2.	Construction	A-15
ARTICLE II. ORGANIZATION
Section 2.1.	Formation	A-16
Section 2.2.	Name	A-16
Section 2.3.	Registered Office; Registered Agent; Principal Office; Other Offices	A-16
Section 2.4.	Purpose and Business	A-16
Section 2.5.	Powers	A-17
Section 2.6.	Power of Attorney	A-17
Section 2.7.	Term	A-18
Section 2.8.	Title to Partnership Assets	A-18
ARTICLE III. RIGHTS OF LIMITED PARTNERS
Section 3.1.	Limitation of Liability	A-18
Section 3.2.	Management of Business	A-18
Section 3.3.	Outside Activities of the Limited Partners	A-19
Section 3.4.	Rights of Limited Partners	A-19
ARTICLE IV. CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
Section 4.1.	Certificates	A-19
Section 4.2.	Mutilated, Destroyed, Lost or Stolen Certificates	A-20
Section 4.3.	Record Holders	A-20
Section 4.4.	Transfer Generally	A-21
Section 4.5.	Registration and Transfer of Limited Partner Interests	A-21
Section 4.6.	Transfer of the General Partner’s General Partner Interest	A-22
Section 4.7.	Transfer of Incentive Distribution Rights	A-22
Section 4.8.	Restrictions on Transfers	A-22
Section 4.9.	Citizenship Certificates; Non-citizen Assignees	A-23
Section 4.10.	Redemption of Partnership Interests of Non-citizen Assignees	A-24
ARTICLE V. CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1.	Organizational Contributions	A-25
Section 5.2.	Contributions by the General Partner and its Affiliates	A-25
Section 5.3.	Contributions by Initial Limited Partners and Distributions to the General Partner and its Affiliates	A-26
Section 5.4.	Interest and Withdrawal	A-26
Section 5.5.	Capital Accounts	A-26
Section 5.6.	Issuances of Additional Partnership Securities	A-28

A-i

Section 5.7.	Conversion of Subordinated Units	A-29
Section 5.8.	Limited Preemptive Right	A-30
Section 5.9.	Splits and Combinations	A-30
Section 5.10.	Fully Paid and Non-Assessable Nature of Limited Partner Interests	A-30
ARTICLE VI. ALLOCATIONS AND DISTRIBUTIONS
Section 6.1.	Allocations for Capital Account Purposes	A-31
Section 6.2.	Allocations for Tax Purposes	A-37
Section 6.3.	Requirement and Characterization of Distributions; Distributions to Record Holders	A-38
Section 6.4.	Distributions of Available Cash from Operating Surplus	A-39
Section 6.5.	Distributions of Available Cash from Capital Surplus	A-40
Section 6.6.	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels	A-41
Section 6.7.	Special Provisions Relating to the Holders of Subordinated Units	A-41
Section 6.8.	Special Provisions Relating to the Holders of Incentive Distribution Rights	A-42
Section 6.9.	Entity-Level Taxation	A-42
ARTICLE VII. MANAGEMENT AND OPERATION OF BUSINESS
Section 7.1.	Management	A-42
Section 7.2.	Certificate of Limited Partnership	A-44
Section 7.3.	Restrictions on the General Partner’s Authority	A-44
Section 7.4.	Reimbursement of the General Partner	A-44
Section 7.5.	Outside Activities	A-45
Section 7.6.	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-46
Section 7.7.	Indemnification	A-46
Section 7.8.	Liability of Indemnitees	A-48
Section 7.9.	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-48
Section 7.10.	Other Matters Concerning the General Partner	A-50
Section 7.11.	Purchase or Sale of Partnership Securities	A-50
Section 7.12.	Registration Rights of the General Partner and its Affiliates	A-50
Section 7.13.	Reliance by Third Parties	A-53
ARTICLE VIII. BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1.	Records and Accounting	A-53
Section 8.2.	Fiscal Year	A-54
Section 8.3.	Reports	A-54
ARTICLE IX. TAX MATTERS
Section 9.1.	Tax Returns and Information	A-54
Section 9.2.	Tax Elections	A-54
Section 9.3.	Tax Controversies	A-54
Section 9.4.	Withholding	A-55

A-ii

ARTICLE X. ADMISSION OF PARTNERS
Section 10.1.	Admission of Initial Limited Partners	A-55
Section 10.2.	Admission of Limited Partners	A-55
Section 10.3.	Admission of Successor General Partner	A-56
Section 10.4.	Amendment of Agreement and Certificate of Limited Partnership	A-56
ARTICLE XI. WITHDRAWAL OR REMOVAL OF PARTNERS
Section 11.1.	Withdrawal of the General Partner	A-56
Section 11.2.	Removal of the General Partner	A-57
Section 11.3.	Interest of Departing Partner and Successor General Partner	A-58
Section 11.4.	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages	A-59
Section 11.5.	Withdrawal of Limited Partners	A-59
ARTICLE XII. DISSOLUTION AND LIQUIDATION
Section 12.1.	Dissolution	A-59
Section 12.2.	Continuation of the Business of the Partnership After Dissolution	A-60
Section 12.3.	Liquidator	A-60
Section 12.4.	Liquidation	A-61
Section 12.5.	Cancellation of Certificate of Limited Partnership	A-61
Section 12.6.	Return of Contributions	A-62
Section 12.7.	Waiver of Partition	A-62
Section 12.8.	Capital Account Restoration	A-62
ARTICLE XIII. AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1.	Amendments to be Adopted Solely by the General Partner	A-62
Section 13.2.	Amendment Procedures	A-63
Section 13.3.	Amendment Requirements	A-63
Section 13.4.	Special Meetings	A-64
Section 13.5.	Notice of a Meeting	A-64
Section 13.6.	Record Date	A-65
Section 13.7.	Adjournment	A-65
Section 13.8.	Waiver of Notice; Approval of Meeting; Approval of Minutes	A-65
Section 13.9.	Quorum and Voting	A-65
Section 13.10.	Conduct of a Meeting	A-66
Section 13.11.	Action Without a Meeting	A-66
Section 13.12.	Right to Vote and Related Matters	A-66
ARTICLE XIV. MERGER
Section 14.1.	Authority	A-67
Section 14.2.	Procedure for Merger or Consolidation	A-67
Section 14.3.	Approval by Limited Partners of Merger or Consolidation	A-68
Section 14.4.	Certificate of Merger	A-69

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Section 14.5.	Amendment of Partnership Agreement	A-69
Section 14.6.	Effect of Merger	A-69
ARTICLE XV. RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
Section 15.1.	Right to Acquire Limited Partner Interests	A-69
ARTICLE XVI. GENERAL PROVISIONS
Section 16.1.	Addresses and Notices	A-71
Section 16.2.	Further Action	A-71
Section 16.3.	Binding Effect	A-71
Section 16.4.	Integration	A-71
Section 16.5.	Creditors	A-71
Section 16.6.	Waiver	A-72
Section 16.7.	Third-Party Beneficiaries	A-72
Section 16.8.	Counterparts	A-72
Section 16.9.	Applicable Law	A-72
Section 16.10.	Invalidity of Provisions	A-72
Section 16.11.	Consent of Partners	A-72
Section 16.12.	Facsimile Signatures	A-72

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AMENDED AND RESTATED AGREEMENT OF

LIMITED PARTNERSHIP OF REGENCY ENERGY PARTNERS LP

      THIS AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF REGENCY ENERGY PARTNERS LP dated as of February 3, 2006, is entered into by and between Regency GP LP a Delaware limited partnership, as the General Partner, and Regency Acquisition LLC, a Delaware limited liability company, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I.

DEFINITIONS

Section 1.1.     Definitions.

      The following terms shall be defined for all purposes of this Agreement as follows, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

      “Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the operating capacity or revenues of the Partnership Group from the operating capacity or revenues of the Partnership Group existing immediately prior to such transaction.

      “Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

      (i) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

      (ii) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).

      “Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

      “Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704 2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be

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allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751 1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit or an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

      “Adjusted Operating Surplus” means, with respect to any period, Operating Surplus generated with respect to such period (a) less (i) any net increase in Working Capital Borrowings with respect to such period and (ii) any net reduction in cash reserves for Operating Expenditures with respect to such period to the extent such reduction does not relate to an Operating Expenditure made with respect to such period, and (b) plus (i) any net decrease in Working Capital Borrowings with respect to such period, and (ii) any net increase in cash reserves for Operating Expenditures with respect to such period to the extent such reserve is required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clauses (a)(i) and (a)(ii) of the definition of Operating Surplus.

      “Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii).

      “Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

      “Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

      “Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

      “Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

      “Agreement” means this Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP, as it may be amended, supplemented or restated from time to time.

      “Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

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      “Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

      (a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter, and (ii) all additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less

      (b) the amount of any cash reserves established by the General Partner to (i) to provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) to comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) to provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters; provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

      Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

      “Board of Directors” means the board of directors or managers of a corporation or limited liability company, as applicable, or if a limited partnership, the board of directors or board of managers of the general partner of such limited partnership, as applicable.

      “Book Basis Derivative Item” means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

      “Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

      “Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

      “Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

      “Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of New York shall not be regarded as a Business Day.

      “Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit, an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Capital Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such

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Partner from and after the date on which such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

      “Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.

      “Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new, capital assets (including, without limitation, any hydrocarbon gathering systems or pipelines, any natural gas processing or natural gas liquids fractionation facilities, any storage or terminal facilities and any related or similar midstream assets), in each case if such addition, improvement, acquisition or construction is made to increase the operating capacity or revenues of the Partnership Group, from the operating capacity or revenues of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition or construction.

      “Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

      “Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d)(i) and Section 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

      “Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

      “Certificate” means a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

      “Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

      “Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

      “Claim” (as used in Section 7.12(d)) has the meaning assigned to such term in Section 7.12(d).

      “Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

      “Closing Price” has the meaning assigned to such term in Section 15.1(a).

      “Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

      “Combined Interest” has the meaning assigned to such term in Section 11.3(a).

      “Commission” means the United States Securities and Exchange Commission.

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      “Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

      “Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

      “Conflicts Committee” means a committee of the Board of Directors of the general partner of the General Partner composed entirely of two or more directors who are not (a) security holders, officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner or (c) holders of any ownership interest in the Partnership Group other than Common Units and who also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading.

      “Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

      “Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the OLP GP, the Operating Partnership, Regency Gas, Regency Acquisition and the other parties named therein, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

      “Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

      “Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

      “Current Market Price” has the meaning assigned to such term in Section 15.1(a).

      “Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

      “Departing Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

      “Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

      “Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752 2(a).

      “Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Limited Partner the General Partner determines does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

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      “Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.

      “Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

      “Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x).

      “First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(D).

      “First Target Distribution” means $0.4025 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on March 31, 2006, it means the product of $0.4025 multiplied by a fraction of which the numerator is the number of days in such period, and of which the denominator is 90), subject to adjustment in accordance with Section 6.6 and Section 6.9.

      “Fully Diluted Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Partnership Securities and options, rights, warrants and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, that for purposes of determining the number of Outstanding Units on a Fully Diluted Basis when calculating whether the Subordination Period has ended or the Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Securities, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

      “General Partner” means Regency GP LP, a Delaware limited partnership, (and where applicable, its general partner, Regency GP LLC) and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

      “General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

      “General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

      “Group” means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

      “Group Member” means a member of the Partnership Group.

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      “Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

      “Hicks Muse” means Hicks, Muse, Tate & Furst Incorporated, a Texas corporation and its affiliates.

      “Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

      “Incentive Distribution Right” means a non-voting Limited Partner Interest issued to the General Partner, which Partnership Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

      “Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4(a)(v), (vi) and (vii) and Section 6.4(b)(iii), (iv) and (v).

      “Indemnified Persons” has the meaning assigned to such term in Section 7.12(d).

      “Indemnitee” means (a) the General Partner, (b) any Departing Partner, (c) any Person who is or was an Affiliate of the General Partner (including Hicks Muse and its Subsidiaries) or any Departing Partner, (d) any Person who is or was a member, partner, director, officer, fiduciary or trustee of any Person that any of the preceding clauses of this definition describes, (e) any Person who is or was serving at the request of the General Partner or any Departing Partner or any Affiliate of the General Partner or any Departing Partner as an officer, director, member, partner, fiduciary or trustee of another Person, provided that that Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

      “Initial Common Units” means the Common Units sold in the Initial Offering.

      “Initial Limited Partners” means Regency Acquisition and the General Partner (with respect to the Incentive Distribution Rights received by it pursuant to Section 5.2), and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

      “Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

      “Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

      “Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group

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Member (including the Common Units sold to the Underwriters in the Initial Offering as well as pursuant to the exercise of the Over-Allotment Option); and (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements.

      “Issue Price” means the price at which a Unit is purchased from the Partnership, excluding any sales commission or underwriting discount charged to the Partnership.

      “Limited Partner” means, unless the context otherwise requires, (a) the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

      “Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may otherwise be required by law.

      “Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

      “Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

      “Merger Agreement” has the meaning assigned to such term in Section 14.1.

      “Minimum Quarterly Distribution” means $0.35 per Unit per Quarter (or with respect to the period commencing on the Closing Date and ending on December 31, 2005, it means the product of $0.35 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 6.6 and Section 6.9.

      “National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute, or The Nasdaq Stock Market or any successor thereto.

      “Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

      “Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net

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Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

      “Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

      “Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

      “Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

      “Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

      “Non-citizen Assignee” means a Person whom the General Partner has determined does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become the Limited Partner, pursuant to Section 4.9.

      “Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b)(i)(A), Section 6.2(b)(ii)(A) and Section 6.2(b)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

      “Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

      “Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752 1(a)(2).

      “Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

      “OLP GP” mean Regency OLP GP LLC, a Delaware limited liability company and the general partner of the Operating Partnership, and any successors thereto.

      “Operating Expenditures” means all Partnership Group cash expenditures, including, without limitation, taxes, reimbursements of the General Partner, repayment of Working Capital Borrowings, debt service payments and capital expenditures, subject to the following:

      (a) repayment of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid;

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      (b) payments (including prepayments) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures; and

      (c) Operating Expenditures shall not include (i) capital expenditures made for Acquisitions or Capital Improvements, (ii) payment of transaction expenses relating to Interim Capital Transactions or (iii) distributions to Partners.

      Where capital expenditures are made in part for Acquisitions or for Capital Improvements and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for other purposes, the period over which the capital expenditures made for other purposes will be deducted as an Operating Expenditure in calculating Operating Surplus.

      “Operating Partnership” means Regency Gas Services LP, a Delaware limited partnership, and any successors thereto.

      “Operating Partnership Agreement” means the Agreement of the Limited Partnership of the Operating Partnership, as it may be amended, supplemented or restated from time to time.

      “Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

      (a) the sum of (i) $20.0 million, (ii) all cash and cash equivalents of the Partnership Group on hand as of the close of business on the Closing Date, (iii) all cash receipts of the Partnership Group for the period beginning on the Closing Date and ending on the last day of such period, other than cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5) and (iv) all cash receipts of the Partnership Group after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, less

      (b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period (other than Operating Expenditures funded with cash reserves established pursuant to clause (ii) of this paragraph (b)) and (ii) the amount of cash reserves established by the General Partner to provide funds for future Operating Expenditures and (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

      Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

      “Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

      “Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

      “Organizational Limited Partner” means Regency Acquisition in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

      “Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that, if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, none of the Partnership Securities owned by such Person or Group shall be voted on any matter and shall be considered to be Outstanding when sending notices of a meeting of Limited

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Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) to any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the general partner of the General Partner.

      “Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

      “Parity Units” means Common Units and all other Units of any other class or series that have the right (i) to receive distributions of Available Cash from Operating Surplus pursuant to each of subclauses (a)(i) and (a)(ii) of Section 6.4 in the same order of priority as the Common Units are entitled to participate in such distributions or (ii) to participate in allocations of Net Termination Gain pursuant to Section 6.1(c)(i)(B) in the same order of priority as the Common Units are entitled to participate, in each case regardless of whether the amounts or value so distributed or allocated on each Parity Unit equals the amount or value so distributed or allocated on each Common Unit. Units whose participation in such (i) distributions of Available Cash from Operating Surplus and (ii) allocations of Net Termination Gain are subordinate in order of priority to such distributions and allocations on Common Units shall not constitute Parity Units even if such Units are convertible under certain circumstances into Common Units or Parity Units.

      “Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

      “Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

      “Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

      “Partners” means the General Partner and the Limited Partners.

      “Partnership” means Regency Energy Partners LP, a Delaware limited partnership, and any successors thereto.

      “Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

      “Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

      “Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

      “Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including without limitation, Common Units, Subordinated Units and Incentive Distribution Rights.

      “Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

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      “Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to General Partner Units and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of all Outstanding Units and all General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

      “Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, governmental agency or political subdivision thereof or other entity.

      “Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when modifying Partners or Record Holders, apportioned among all Partners or Record Holders, as the case may be, in accordance with their relative Percentage Interests and (c) when modifying holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

      “Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

      “Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the first fiscal quarter of the Partnership after the Closing Date, the portion of such fiscal quarter after the Closing Date.

      “Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

      “Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

      “Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

      “Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

      “Regency Acquisition” means Regency Acquisition LLC, a Delaware limited liability company, and any successors thereto.

      “Regency Gas” means Regency Gas Services LLC, a Delaware limited liability company, and any successors thereto.

      “Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-128322) as it has been and it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering, sale and delivery of the Common Units in the Initial Offering.

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      “Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

      “Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(vii) or Section 6.1(d)(ix).

      “Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss is not allocated pursuant to Section 6.2(b)(i)(A) or Section 6.2(b)(ii)(A), respectively, to eliminate Book-Tax Disparities.

      “Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E).

      “Second Target Distribution” means $0.4375 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on March 31, 2006, it means the product of $0.4375 multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 90), subject to adjustment in accordance with Section 6.6 and Section 6.9.

      “Securities Act” means the Securities Act of 1933, as amended, from time to time and any successor to such statute.

      “Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

      “Special Approval” means approval by a majority of the members of the Conflicts Committee.

      “Subordinated Unit” means a Unit representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” as used herein does not include a Common Unit or Parity Unit. A Subordinated Unit that is convertible into a Common Unit or a Parity Unit shall not constitute a Common Unit or Parity Unit until such conversion occurs.

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      “Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

      (a) the first day of any Quarter beginning after December 31, 2008 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods and (B) the Adjusted Operating Surplus generated during each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units and Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis, plus the related distribution on the General Partner Units, during such periods and (ii) there are no Cumulative Common Unit Arrearages; and

      (b) The first date on which there are no longer outstanding Subordinated Units due to the conversion of all Subordinated Units under section 517(b).

      (c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal.

      “Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, and if a limited partner, only it has the power to remove the general partner or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

      “Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

      “Third Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F).

      “Third Target Distribution” means $0.5250 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on March 31, 2006, it means the product of $0.5250 multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 90), subject to adjustment in accordance with Section 6.6 and Section 6.9.

      “Trading Day” has the meaning assigned to such term in Section 15.1(a).

      “Transfer” has the meaning assigned to such term in Section 4.4(a).

      “Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

      “Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

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      “Underwriting Agreement” means the Underwriting Agreement dated                     , 2006 among the Underwriters, the Partnership, the General Partner, the OLP GP, the Operating Partnership and other parties thereto, providing for the purchase of Common Units by such Underwriters.

      “Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

      “Unit Majority” means, during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates) voting as a class and at least a majority of the Outstanding Subordinated Units voting as a single class, and after the end of the Subordination Period, at least a majority of the Outstanding Units.

      “Unitholders” means the holders of Units.

      “Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B).

      “Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

      “Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

      “Unrecovered Capital” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

      “U.S. GAAP” means United States generally accepted accounting principles consistently applied.

      “Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

      “Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility, commercial paper facility or similar financing arrangement; provided that when incurred it is the intent of the borrower to repay such borrowings within 12 months from other than additional Working Capital Borrowings.

Section 1.2.     Construction.

      Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation; and (d) the conjunctive “and” and “or” shall include both the conjunctive and the disjunctive.

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ARTICLE II.

ORGANIZATION

Section 2.1.     Formation.

      The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Regency Energy Partners LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes and a Partner has no interest in specific Partnership property.

Section 2.2.     Name.

      The name of the Partnership shall be “Regency Energy Partners LP.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3.     Registered Office; Registered Agent; Principal Office; Other Offices.

      Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporation Trust Center. The principal office of the Partnership shall be located at 1700 Pacific, Suite 2900, Dallas, Texas 75201 or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 1700 Pacific, Suite 2900, Dallas, Texas 75201 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4.     Purpose and Business.

      The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold or dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other

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standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5.     Powers.

      The Partnership shall be empowered to do any and all acts and things necessary and appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6.     Power of Attorney.

      (a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead:

      (i) to execute, swear to, acknowledge, deliver, file and record in the appropriate public offices all certificates, documents and other instruments (A) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof); (B) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement including conveyances and a certificate of cancellation; (D) relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV (including agreements and a certificate of merger); and

      (ii) to execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) to make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, however, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

      (b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner, the transfer of all or any portion of such Limited Partner’s Limited Partner Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the

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Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

Section 2.7.     Term.

      The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8.     Title to Partnership Assets.

      Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable.

ARTICLE III.

RIGHTS OF LIMITED PARTNERS

Section 3.1.     Limitation of Liability.

      The Limited Partners and assignees shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2.     Management of Business.

      No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners or assignees under this Agreement.

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Section 3.3.     Outside Activities of the Limited Partners.

      Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4.     Rights of Limited Partners.

      (a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense:

      (i) promptly after becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

      (ii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

      (iii) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution which each other Partner has made or agreed to contribute in the future, and the date on which each other Partner became a Partner;

      (iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with a copy of each power of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

      (v) to obtain true and full information regarding the status of the business and financial condition of the Partnership Group; and

      (vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

      (b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV.

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1.     Certificates.

      Upon the Partnership’s issuance of Common Units or Subordinated Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Units and (b) upon the request of any Person owning Incentive Distribution Rights or any other Partnership Securities other than Common Units or Subordinated Units,

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the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or other Partnership Securities other than Common Units or Subordinated Units. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), the Partners holding Certificates evidencing Subordinated Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7.

Section 4.2.     Mutilated, Destroyed, Lost or Stolen Certificates.

      (a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

      (b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

      (i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

      (ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

      (iii) upon request by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

      (iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

      (c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3.     Record Holders.

      The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership

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Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.

Section 4.4.     Transfer Generally.

      (a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange and any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange and any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

      (b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

      (c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner.

Section 4.5.     Registration and Transfer of Limited Partner Interests.

      (a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

      (b) Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

      (c) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights) shall be freely transferable.

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      (d) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

Section 4.6.     Transfer of the General Partner’s General Partner Interest.

      (a) Subject to Section 4.6(c) below, prior to December 31, 2015, the General Partner shall not transfer all or any part of its General Partner Interest (represented by General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

      (b) Subject to Section 4.6(c) below, on or after December 31, 2015, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

      (c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7.     Transfer of Incentive Distribution Rights.

      Prior to December 31, 2015, a holder of Incentive Distribution Rights may transfer any or all of the Incentive Distribution Rights held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder (other than an individual) or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person or (iii) the sale of all of the ownership interests in such holder. Any other transfer of the Incentive Distribution Rights prior to December 31, 2015 shall require the prior approval of holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates). On or after December 31, 2015, the General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

Section 4.8.     Restrictions on Transfers.

      (a) Except as provided in Section 4.8(d) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its

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formation or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

      (b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

      (c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(c).

      (d) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

      (e) If any Partnership Interest is evidenced in certificated form, each such certificate shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF REGENCY ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF REGENCY ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE REGENCY ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). REGENCY GP LP, THE GENERAL PARTNER OF REGENCY ENERGY PARTNERS LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF REGENCY ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9.     Citizenship Certificates; Non-citizen Assignees.

      (a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the General Partner determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited

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Partner fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner is not an Eligible Citizen, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

      (b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.

      (c) Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

      (d) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, such Non-citizen Assignee be admitted as a Limited Partner, and upon approval of the General Partner, such Non-citizen Assignee shall be admitted as a Limited Partner and shall no longer constitute a Non-citizen Assignee and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

Section 4.10. Redemption of Partnership Interests of Non-citizen Assignees.

      (a) If at any time a Limited Partner fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

      (i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

      (ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 10%

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annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

      (iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.

      (iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

      (b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Citizen.

      (c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V.

CAPITAL CONTRIBUTIONS AND ISSUANCE

OF PARTNERSHIP INTERESTS

Section 5.1.     Organizational Contributions.

      In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $20.00, for a 2% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $980 for a 98% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, the interest of the Organizational Limited Partner shall be redeemed; and the initial Capital Contribution of the Organizational Limited Partner shall thereupon be refunded. Ninety-eight percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

Section 5.2.     Contributions by the General Partner and its Affiliates.

      (a) On the Closing Date and pursuant to the Contribution Agreement: (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, all of its ownership interests in the Operating Partnership in exchange for (A) a continuation of its 2% General Partner Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement and (B) the Incentive Distribution Rights; and (ii) Regency Acquisition shall contribute to the Partnership, as a Capital Contribution, all of (A) its member interest in the OLP GP and (B) all of its ownership interest in the Operating Partnership in exchange for 5,353,896 Common Units, 19,103,896 Subordinated Units and the right to receive $197.0 million in cash to reimburse it for certain capital expenditures incurred by it or an affiliate.

      (b) Upon the issuance of any additional Limited Partner Interests by the Partnership, the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100% less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for

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such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3. Contributions by Initial Limited Partners and Distributions to the General Partner and its Affiliates.

      (a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

      (b) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to subparagraph (a) hereof in aggregate number equal to 13,750,000, (ii) the 5,353,896 Common Units and 19,103,896 Subordinated Units issuable pursuant to Section 5.2 hereof, (iii) the Incentive Distribution Rights and (iv) any Common Units issuable under, or to satisfy the obligations of the Partnership or any of its Affiliates under the Regency GP LLC Long-Term Incentive Plan. No additional Limited Partner Interests will be issued in connection with any exercise of the Over-Allotment Option. If the Underwriters exercise their Over-Allotment-Option, the Partnership shall use the net proceeds from such exercise to redeem an equal number of Common Units from Regency Acquisition

Section 5.4.     Interest and Withdrawal.

      No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5.     Capital Accounts.

      (a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

      (b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination,

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recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

      (i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

      (ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

      (iii) Except as otherwise provided in Treasury Regulation Section 1.704 1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

      (iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

      (v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery or amortization derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any method that the General Partner may adopt.

      (vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

      (c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

      (ii) Immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to

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an Affiliate unless the General Partner elects to have this Section 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units. Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

      (d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

      (ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6.     Issuances of Additional Partnership Securities.

      (a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

      (b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such

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designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

      (c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest (represented by General Partner Units) or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) the admission of Additional Limited Partners and (iv) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

      (d) No fractional Units shall be issued by the Partnership.

Section 5.7.     Conversion of Subordinated Units.

      (a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of the final Quarter of the Subordination Period.

      (b) Notwithstanding Section 5.7(a) above, the Subordination Period shall terminate and all Outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2006, in respect of which:

      (i) distributions under Section 6.4 in respect of all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to the four-Quarter period immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such period;

      (ii) the Adjusted Operating Surplus generated during the consecutive four-Quarter period immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such period on a Fully Diluted Basis, plus the related distribution on the General Partner Units during such period; and

      (iii) the Cumulative Common Unit Arrearage on all of the Common Units is zero.

      (c) Notwithstanding any other provision of this Agreement, all the Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

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      (d) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7(b).

Section 5.8.     Limited Preemptive Right.

      Except as provided in this Section 5.8 and in Section 5.2(b), no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.9.     Splits and Combinations.

      (a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

      (b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

      (c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

      (d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10.     Fully Paid and Non-Assessable Nature of Limited Partner Interests.

      All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

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ARTICLE VI.

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1.     Allocations for Capital Account Purposes.

      For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

      (a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable year shall be allocated as follows:

      (i) First, 100% to the General Partner, in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years;

      (ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this Section 6.1(a)(ii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable years; and

      (iii) Third, the balance, if any, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests.

      (b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated as follows:

      (i) First, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Losses allocated pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable years; provided, that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

      (ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and

      (iii) Third, the balance, if any, 100% to the General Partner.

      (c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available

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Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

      (i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

      A. First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

      B. Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital plus (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

      C. Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (c), until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Capital, determined for the taxable year (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

      D. Fourth, 100% to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount”);

      E. Fifth, (x) to the General Partner in accordance with its Percentage Interest and (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount”);

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      F. Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv) (the sum of (1) and (2) is hereinafter defined as the “Third Liquidation Target Amount”); and

      G. Finally, (x) to the General Partner in accordance with its Percentage Interest and (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (G).

      (ii) Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

      A. First, if such Net Termination Loss is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (A), until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

      B. Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

      C. Third, the balance, if any, 100% to the General Partner.

      (d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

      (i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704 2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

      (ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each

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Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

      (iii) Priority Allocations.

      A. If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) each Unitholder receiving such greater cash or property distribution shall be allocated gross income in an amount equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated gross income in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1) above.

      B. After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable year and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

      (iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

      (v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations

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provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

      (vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

      (vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

      (viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

      (ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

      (x) Economic Uniformity. At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of such Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount equal to the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

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      (xi) Curative Allocation.

      A. Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

      B. The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

      (xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

      A. In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate additional items of gross income and gain away from the holders of Incentive Distribution Rights to the Unitholders and the General Partner, or additional items of deduction and loss away from the Unitholders and the General Partner to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

      B. In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount

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that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

      C. In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

Section 6.2.     Allocations for Tax Purposes.

      (a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

      (b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

      (i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

      (ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

      (iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

      (c) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including, without limitation, gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

      (d) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all

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purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

      (e) Any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

      (f) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

      (g) Each item of Partnership income, gain, loss and deduction shall for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Units are then traded on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Units are then traded on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Units are then traded on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

      (h) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3. Requirement and Characterization of Distributions; Distributions to Record Holders.

      (a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2005, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

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      (b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

      (c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

      (d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4.     Distributions of Available Cash from Operating Surplus.

      (a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise required by Section 5.6(b) in respect of other Partnership Securities issued pursuant thereto:

      (i) First, (A) to the General Partner in accordance with its Percentage Interest and (B) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

      (ii) Second, (A) to the General Partner in accordance with its Percentage Interest and (B) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

      (iii) Third, (A) to the General Partner in accordance with its Percentage Interest and (B) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

      (iv) Fourth, to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

      (v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

      (vi) Sixth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this subclause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

      (vii) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders,

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Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).

      (b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5, subject to Section 17-607 of the Delaware Act, shall be distributed as follows, except as otherwise required by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:

      (i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

      (ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

      (iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

      (iv) Fourth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

      (v) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(v).

Section 6.5. Distributions of Available Cash from Capital Surplus.

      Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed (A) to the General Partner in accordance with its Percentage Interest and (B) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the

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Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6. Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

      (a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Third Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Securities in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Capital of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Capital of the Common Units immediately prior to giving effect to such distribution.

      (b) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall also be subject to adjustment pursuant to Section 6.9.

Section 6.7. Special Provisions Relating to the Holders of Subordinated Units.

      (a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x) and Section 6.7(c).

      (b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.8 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or retained converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

      (c) The Unitholder holding a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer its converted Subordinated Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that a converted Subordinated Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In providing such advice, counsel may rely upon the fact that the General Partner will take positions in filing the tax returns of the Partnership (including information returns to unitholders) which are intended to preserve the uniformity of units, as described at “Material Tax Consequences — Uniformity of Units” in the Registration Statement, and may assume the validity of such positions. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to the converted Subordinated Units in preparation for a transfer of such converted Subordinated Units, including the application of Section 5.5(c)(ii) and Section 6.1(d)(x); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

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Section 6.8. Special Provisions Relating to the Holders of Incentive Distribution Rights.

      Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Section 6.4(a)(v), (vi) and (vii), Section 6.4(b)(iii), (iv) and (v), and Section 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

Section 6.9. Entity-Level Taxation.

      If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Group Member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the General Partner shall estimate for each Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all such income taxes that are payable by reason of any such new legislation or interpretation; provided that any difference between such estimate and the actual tax liability for such Quarter that is owed by reason of any such new legislation or interpretation shall be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII.

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1. Management.

      (a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

      (i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

      (ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

      (iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with

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or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3);

      (iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

      (v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

      (vi) the distribution of Partnership cash;

      (vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

      (viii) the maintenance of insurance for the benefit of the Partnership Group and the Partners;

      (ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

      (x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

      (xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

      (xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

      (xiii) the purchase, sale or other acquisition or disposition of Partnership Securities and the issuance of additional options, rights, warrants and appreciation rights relating to Partnership Securities;

      (xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

      (xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

      (b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Contribution Agreement, any Group Member Agreement of any other Group Member and the other agreements described in or filed as exhibits to the Registration Statement that are related to the

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transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2. Certificate of Limited Partnership.

      The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3. Restrictions on the General Partner’s Authority.

      (a) Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4. Reimbursement of the General Partner.

      (a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

      (b) The General Partner and its general partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group, which amount shall also include reimbursement for any Common Units purchased to satisfy obligations of the Partnership under any of its equity compensation plans), and (ii) all other expenses allocable to the

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Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates and payments pursuant to indemnification obligations of the General Partner and its general partner). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

      (c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership or in the market to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest (represented by General Partner Units) pursuant to Section 4.6.

Section 7.5. Outside Activities.

      (a) After the Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership), and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

      (b) Each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner. Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or of any Indemnitee for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership.

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      (c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner). No Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.

      (d) None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.

      (e) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. For purposes of this Section 7.5(d), the term “Affiliates,” when used with respect to the General Partner, shall not include any Group Member.

Section 7.6. Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

      (a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

      (b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

      (c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7. Indemnification.

      (a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in

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which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred in its or their individual capacities pursuant to the Underwriting Agreement or the Contribution Agreement (other than obligations incurred by the General Partner or its Affiliates on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or lend any monies or property to the Partnership to enable it to effectuate such indemnification.

      (b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of an undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

      (c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

      (d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

      (e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

      (f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

      (g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

      (h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

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      (i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8. Liability of Indemnitees.

      (a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

      (b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

      (c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, no such Indemnitee (including the General Partner) and any other Indemnitee acting in connection with the Partnership’s business or affairs shall be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

      (d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9. Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

      (a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors of the General

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Partner acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

      (b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

      (c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.

      (d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

      (e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

      (f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

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Section 7.10. Other Matters Concerning the General Partner.

      (a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

      (b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

      (c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11. Purchase or Sale of Partnership Securities.

      The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities; provided that, except as permitted by Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Article IV and Article X.

Section 7.12. Registration Rights of the General Partner and its Affiliates.

      (a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “Holder”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to Section 7.12(a) and Section 7.12(b); and provided further, however, that if the Conflicts Committee determines that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than three months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) or Section 7.12(b) not to be utilized more than twice in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and

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sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

      (b) If any Holder holds Partnership Securities that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such shelf registration statement have been sold, a “shelf” registration statement covering the Partnership Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to Section 7.12(a) and this Section 7.12(b); and provided further, however, that if the Conflicts Committee determines in good faith that any offering under, or the use of any prospectus forming a part of, the shelf registration statement would be materially detrimental to the Partnership and its Partners because such offering or use would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to suspend such offering or use for a period of not more than [three] months after receipt of the Holder’s request, such right pursuant to Section 7.12(a) or this Section 7.12(b) not to be utilized more than twice in any twelve-month period.

      (c) Except as provided in the first sentence of each Subsection (a) and (b) of this Section 7.12, the Partnership shall be deemed not to have used all reasonable efforts to keep the shelf registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any shelf registration pursuant to Subsection (a) or (b) of this Section 7.12, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(e), all costs and expenses of any such shelf registration and

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offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

      (d) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall use all reasonable efforts to provide notice of its intention to file such registration statement and shall use all reasonable offers to include such number or amount of securities held by the Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the securities of the Holder once the registration statement is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(d) shall be an underwritten offering, then, if the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

      (e) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(e) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

      (f) The provisions of Section 7.12(a), Section 7.12(b) and Section 7.12(d) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a General Partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for

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which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

      (g) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

      (h) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13. Reliance by Third Parties.

      Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII.

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1. Records and Accounting.

      The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders and assignees of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly

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legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2. Fiscal Year.

      The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3. Reports.

      (a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

      (b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX.

TAX MATTERS

Section 9.1. Tax Returns and Information.

      The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2. Tax Elections.

      (a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

      (b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3. Tax Controversies.

      Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s

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expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4. Withholding.

      Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X.

ADMISSION OF PARTNERS

Section 10.1. Admission of Initial Limited Partners.

      Upon the issuance by the Partnership of Common Units, Subordinated Units and Incentive Distribution Rights to the General Partner, Regency Acquisition and the Underwriters as described in Section 5.2 and Section 5.3 in connection with the Initial Offering, the General Partner shall admit such parties to the Partnership as Initial Limited Partners in respect of the Common Units, Subordinated Units or Incentive Distribution Rights issued to them.

Section 10.2. Admission of Limited Partners.

      (a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.9 hereof.

      (b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1 hereof.

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      (c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.2(a).

Section 10.3. Admission of Successor General Partner.

      A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest (represented by General Partners Units) pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest (represented by General Partners Units) pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.4. Amendment of Agreement and Certificate of Limited Partnership.

      To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI.

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1. Withdrawal of the General Partner.

      (a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

      (i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

      (ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

      (iii) The General Partner is removed pursuant to Section 11.2;

      (iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

      (v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

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      (vi) If the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) if the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

      (b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Time, on December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Time, on December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

Section 11.2. Removal of the General Partner.

      The General Partner may be removed if such removal is approved by the Unitholders holding at least 66²/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units voting as a class and a majority of the outstanding Subordinated Units voting as a class

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(including Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.

Section 11.3. Interest of Departing Partner and Successor General Partner.

      (a) In the event of (i) withdrawal of the General Partner under circumstances in which such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing Partner shall have the option, exercisable prior to the effective date of the departure of such Departing Partner, to require its successor to purchase its General Partner Interest (represented by General Partners Units) and its general partner interest (or equivalent interest), if any, in the other Group Members and all of its Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing Partner. In either event, the Departing Partner shall be entitled to receive all reimbursements due such Departing Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Departing Partner’s Combined Interest shall be determined by agreement between the Departing Partner and its successor or, failing agreement within 30 days after the effective date of such Departing Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing Partner shall designate an independent investment banking firm or other independent expert, the Departing Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing Partner and other factors it may deem relevant.

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      (b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing Partner to Common Units will be characterized as if the Departing Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

      (c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the Percentage Interest of the Departing Partner and the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4. Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.

      Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis, (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest (represented by General Partner Units) and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor.

Section 11.5. Withdrawal of Limited Partners.

      No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII.

DISSOLUTION AND LIQUIDATION

Section 12.1. Dissolution.

      The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner

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shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

      (a) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

      (b) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act;

      (c) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3; or

      (d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2. Continuation of the Business of the Partnership After Dissolution.

      Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

      (i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

      (ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

      (iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, however, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3. Liquidator.

      Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original

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Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4. Liquidation.

      The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

      (a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

      (b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

      (c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5. Cancellation of Certificate of Limited Partnership.

      Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

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Section 12.6. Return of Contributions.

      The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7. Waiver of Partition.

      To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8. Capital Account Restoration.

      No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII.

AMENDMENT OF PARTNERSHIP AGREEMENT;

MEETINGS; RECORD DATE

Section 13.1. Amendments to be Adopted Solely by the General Partner.

      Each Partner agrees that the General Partner, without the approval of any Partner may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

      (a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

      (b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

      (c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

      (d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) to facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

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      (e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

      (f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

      (g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6;

      (h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

      (i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

      (j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

      (k) an amendment necessary to require Limited Partners to provide a statement, certification or other proof evidence to the Partnership regarding whether such Limited Partner is subject to United States federal income taxation on the income generated by the Partnership;

      (l) a merger or conveyance pursuant to Section 14.3(d); or

      (m) any other amendments substantially similar to the foregoing.

Section 13.2. Amendment Procedures.

      Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3. Amendment Requirements.

      (a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General

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Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

      (b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

      (c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

      (d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable law.

      (e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4. Special Meetings.

      All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5. Notice of a Meeting.

      Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

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Section 13.6. Record Date.

      For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7. Adjournment.

      When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8. Waiver of Notice; Approval of Meeting; Approval of Minutes.

      The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9. Quorum and Voting.

      The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to

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vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10. Conduct of a Meeting.

      The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11. Action Without a Meeting.

      If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12. Right to Vote and Related Matters.

      (a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

      (b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name

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such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV.

MERGER

Section 14.1. Authority.

      The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited including a limited liability partnership), formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) in accordance with this Article XIV.

Section 14.2. Procedure for Merger or Consolidation.

      Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner; provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger or consolidation of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger or consolidation, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

      (a) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

      (b) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

      (c) the terms and conditions of the proposed merger or consolidation;

      (d) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) that the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, the terms on which, such cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

      (e) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate

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or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

      (f) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, however, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

      (g) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

Section 14.3. Approval by Limited Partners of Merger or Consolidation.

      (a) Except as provided in Section 14.3(d) or Section 14.3(e), the General Partner, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.

      (b) Except as provided in Section 14.3(d) or Section 14.3(e), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

      (c) Except as provided in Section 14.3(d) or Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

      (d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

      (e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, and (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation.

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Section 14.4. Certificate of Merger.

      Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5. Amendment of Partnership Agreement.

      Pursuant to Section 17-211(g)of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.6. Effect of Merger.

      (a) At the effective time of the certificate of merger:

      (i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

      (ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and shall not be in any way impaired because of the merger or consolidation;

      (iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

      (iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

      (b) A merger or consolidation effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

ARTICLE XV.

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1. Right to Acquire Limited Partner Interests.

      (a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Limited Partner Interests means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular

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way, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal National Securities Exchange (other than The Nasdaq Stock Market) on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than The Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by The Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted for trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

      (b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).

      (c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such

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Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI.

GENERAL PROVISIONS

Section 16.1. Addresses and Notices.

      Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

Section 16.2. Further Action.

      The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3. Binding Effect.

      This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4. Integration.

      This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5. Creditors.

      None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

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Section 16.6. Waiver.

      No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7. Third-Party Beneficiaries

      Each Partner agrees that any Indemnitee, including Hicks Muse or any of its Subsidiaries, shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

Section 16.8. Counterparts.

      This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.2(a) without execution of this Agreement.

Section 16.9. Applicable Law.

      This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Section 16.10. Invalidity of Provisions.

      If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 16.11. Consent of Partners.

      Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12. Facsimile Signatures.

      The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

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      IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

GENERAL PARTNER:

Regency GP LP,

By:  Regency GP LLC,

its General Partner

By: 

Name: 

Title:

ORGANIZATIONAL LIMITED PARTNER:

Regency Acquisition LLC

By: 

Name: 

Title:

All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner or without execution hereof pursuant to Section 10.2(a) hereof.

Regency GP LP

By:  Regency GP LLC,

its General Partner

By: 

Name: 

Title:

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EXHIBIT A

to the Amended and Restated

Agreement of Limited Partnership of

Regency Energy Partners LP

Certificate Evidencing Common Units

Representing Limited Partner Interests in

Regency Energy Partners LP

No.                      Common Units

CUSIP                     

      In accordance with Section 4.1 of the Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), Regency Energy Partners LP, a Delaware limited partnership (the “Partnership”), hereby certifies that                     (the “Holder”) is the registered owner of                      Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 1700 Pacific, Suite 2900, Dallas, Texas 75201. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

      THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF REGENCY ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF REGENCY ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE REGENCY ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). [REGENCY GP LP], THE GENERAL PARTNER OF REGENCY ENERGY PARTNERS LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF REGENCY ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

      The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

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      This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

Dated:	Regency Energy Partners LP
Countersigned and Registered by:	By: Regency GP LP,     its General Partner
	By: Regency GP LLC,
as Transfer Agent and Registrar	its General Partner
By:	By:
Authorized Signature	Name:
	By:
	Secretary

[Reverse of Certificate]

ABBREVIATIONS

      The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM —	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT
TEN ENT —	as tenants by the entireties	Custodian    (Cust)                               (Minor)
JT TEN —	as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/Transfers to CD Minors Act (State)

      Additional abbreviations, though not in the above list, may also be used.

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ASSIGNMENT OF COMMON UNITS

in

REGENCY ENERGY PARTNERS LP

      FOR VALUE RECEIVED,                     hereby assigns, conveys, sells and transfers unto

(Please print or typewrite name
and address of assignee) (Please insert Social Security or other
identifying number of assignee)

                          Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                     as its attorney-in-fact with full power of substitution to transfer the same on the books of Regency Energy Partners LP

Date: NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.

THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17d-15	(Signature) (Signature)
Signature(s) Guaranteed

      No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

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APPENDIX B

GLOSSARY OF TERMS

      adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:

      (a) decrease operating surplus by:

      (1) any net increase in working capital borrowings with respect to that period; and

      (2) any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

      (b) increase operating surplus by:

      (1) any net decrease in working capital borrowings with respect to that period; and

      (2) any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

      Adjusted operating surplus does not include that portion of operating surplus included in clauses (a)(1) and (a)(2) of the definition of operating surplus.

      available cash: For any quarter ending prior to liquidation:

      (a) the sum of:

      (1) all cash and cash equivalents of Regency Energy Partners LP and its subsidiaries on hand at the end of that quarter; and

      (2) all cash or cash equivalents of Regency Energy Partners LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

      (b) less the amount of cash reserves established by our general partner to:

      (1) provide for the proper conduct of the business of Regency Energy Partners LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Regency Energy Partners LP and its subsidiaries) after that quarter;

      (2) comply with applicable law or any debt instrument or other agreement or obligation to which Regency Energy Partners LP or any of its subsidiaries is a party or its assets are subject; and

      (3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and

provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

      Bbls: Barrels.

      Btu: British Thermal Units.

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      capital account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a general partner unit, a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Regency Energy Partners LP held by a partner.

      capital surplus: All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.

      closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the Nasdaq National Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

      common unit arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

      current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

      interim capital transactions: The following transactions if they occur prior to liquidation:

      (a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by Regency Energy Partners LP or any of its subsidiaries;

      (b) sales of equity interests by Regency Energy Partners LP or any of its subsidiaries; and

      (c) sales or other voluntary or involuntary dispositions of any assets of Regency Energy Partners LP or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements).

      MMBbls: One million barrels.

      MMBtu: One million British Thermal Units.

      MMcf: One million cubic feet of natural gas.

      MBbls: One thousand barrels.

      MBbls/d: One thousand barrels per day.

      MMBtu/d: One million British Thermal Units per day.

      MMcf/d: One million cubic feet per day.

B-2

      NGLs: Natural gas liquids which consist primarily of ethane, propane, normal butane, isobutane and natural gas.

      operating expenditures: All of our cash expenditures and cash expenditures of our subsidiaries, including, without limitation, taxes, reimbursements of our general partner, repayment of working capital borrowings, interest payments and maintenance capital expenditures, subject to the following:

      (a) Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings, will not constitute operating expenditures.

      (b) Operating expenditures will not include:

      (1) capital expenditures made for acquisitions or for capital improvements;

      (2) payment of transaction expenses relating to interim capital transactions; or

      (3) distributions to unitholders.

      Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, our general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for other purposes, the period over which the capital expenditures made for other purposes will be deducted as an operating expenditure in calculating operating surplus.

      operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:

      (a) the sum of:

      (1) $20.0 million;

      (2) all the cash of Regency Energy Partners LP and its subsidiaries on hand as of the closing date of its initial public offering;

      (3) all cash receipts of Regency Energy Partners LP and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and

      (4) all cash receipts of Regency Energy Partners LP and its subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings;

      (b) the sum of:

      (1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and

      (2) the amount of cash reserves that is established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a partner of Regency Energy Partners LP and our subsidiaries or disbursements on behalf of a partner of Regency Energy Partners LP and our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

      subordination period: The subordination period will extend from the closing of the initial public offering until the first to occur of:

      (a) the first day of any quarter beginning after December 31, 2008 for which:

      (1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly

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distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

      (2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four quarter periods, immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the common units and subordinated units that were outstanding during those periods on a fully diluted basis; and

      (3) there are no outstanding cumulative common units arrearages.

      (b) the date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

      throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

B-4

      Until February 24, 2006 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.