Table of Contents

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2005
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from           to

Delaware		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1700 Pacific Avenue, Suite 2900 Dallas, Texas		75201
(Address of principal executive offices)		(Zip Code)

Title of each class		Name of each exchange on which registered
Common Units of Limited Partner Interests		Nasdaq National Market

Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ

Class		Outstanding at March 15, 2006
Common Units		19,103,896
Subordinated Units		19,103,896

---

 

PART I
					PAGE
ITEM 1.		BUSINESS			1
ITEM 1A.		RISK FACTORS			25
ITEM 1B.		UNRESOLVED STAFF COMMENTS			42
ITEM 2.		PROPERTIES			42
ITEM 3.		LEGAL PROCEEDINGS			42
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			43
PART II
ITEM 5.		MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED   UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY   SECURITIES			43
ITEM 6.		SELECTED FINANCIAL DATA			46
ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL   CONDITION AND RESULTS OF OPERATIONS			50
ITEM 7A.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET   RISK			76
ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			78
ITEM 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON   ACCOUNTING AND FINANCIAL DISCLOSURE			78
ITEM 9A.		CONTROLS AND PROCEDURES			78
ITEM 9B.		OTHER INFORMATION			80
PART III
ITEM 10.		DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT			80
ITEM 11.		EXECUTIVE COMPENSATION			87
ITEM 12.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND   MANAGEMENT AND RELATED UNITHOLDER MATTERS			88
ITEM 13.		CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			90
ITEM 14.		PRINCIPAL ACCOUNTING FEES AND SERVICES			95
PART IV
ITEM 15.		EXHIBITS, FINANCIAL STATEMENT SCHEDULES			96
Certifications Pursuant to Rule 13a-14(a)
Certifications Pursuant to Rule 13a-14(a)
Certifications Pursuant to Section 1350
Certifications Pursuant to Section 1350
Financial Statements of Regency GP LP

---

Table of Contents

	•	Gathering and Processing: in which we provide “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 natural gas liquids, or NGLs, from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

1

---

Table of Contents

	•	Transportation: in which we deliver natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project.

	Gathering and Processing Segment

																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

2

---

Table of Contents

	•	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;
	•	extensions of the pipeline east into other fields beyond Winnsboro;
	•	construction and installation of a refrigeration plant at Longwood or Sibley or both;
	•	construction of additional compression at our Mainline Compressor Station;
	•	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.

	•	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

3

---

Table of Contents

		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, approximately 75% in 2007 and approximately 50% in 2008. 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 improving our credit ratings. 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 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.

4

---

Table of Contents

	•	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 northeast 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 markets in northeast 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. The borrowing limit under our revolving credit facility is $160 million. At December 31, 2005 we had borrowed $50 million against this facility. This 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. Members of our senior management team have a substantial economic interest in us.
	•	We are affiliated with HM Capital a leading private equity investment firm headquartered in Dallas, Texas. Our affiliation with HM Capital provides us with significant benefits. We expect that our relationship with HM Capital 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. HM Capital is a leading sector focused private equity firm and is currently managing and investing a $1.6 billion fund. Since the firm’s founding in 1989, HM Capital has completed more than 150 transactions in its core sectors for a total transaction value in excess of $26 billion.

5

---

Table of Contents

6

---

Table of Contents

	General

7

---

Table of Contents

															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

8

---

Table of Contents

	North Louisiana System

9

---

Table of Contents

	West Texas System

10

---

Table of Contents

11

---

Table of Contents

	Mid-Continent Systems

	•	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.

12

---

Table of Contents

	Other Processing Systems

13

---

Table of Contents

											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			320				27,400				800				11
Haughton Refrigeration Processing Plant				—				—				35				—

14

---

Table of Contents

15

---

Table of Contents

16

---

Table of Contents

			Nature of Contract
			(Measured by 2005 volumes)
			Keep-Whole				POP				Fee-Based
Geographic Region
North Louisiana(1)				29.3	%			57.9	%			12.8	%
West Texas				18.0	%			44.5	%			37.5	%
Mid-Continent				31.3	%			46.8	%			21.9	%
	Total Gathering and Processing			26.1	%			48.5	%			25.4	%

Note (1) —	approximately 24% of 29% reported keep-whole exposure in north Louisiana is attributable to a package of bypassable gas controlled by us. We only process this gas when economically beneficial.

17

---

Table of Contents

	•	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.

18

---

Table of Contents

	•	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

19

---

Table of Contents

	•	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.

20

---

Table of Contents

21

---

Table of Contents

22

---

Table of Contents

23

---

Table of Contents

24

---

Table of Contents

25

---

Table of Contents

	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 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.

	•	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;

	•	the cost of acquisitions, if any; and
	•	the amount of cash reserves established by our general partner.

	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.

	•	we are unable to perform the requisite transportation services for any reason,

	•     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.

26

---

Table of Contents

	While substantial amounts of the incremental capacity resulting from the completion of the Regency Intrastate Enhancement Project has been contracted, 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.

27

---

Table of Contents

	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.

	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.

	•	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.

28

---

Table of Contents

	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.

	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.

29

---

Table of Contents

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

	•     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.

	•     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.

30

---

Table of Contents

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

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

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

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

	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.

31

---

Table of Contents

	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.

	•     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
	•     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.

	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.

	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.

	•     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 pipelines, 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.

32

---

Table of Contents

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

	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.

	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.

	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.

33

---

Table of Contents

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

	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.

34

---

Table of Contents

	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.

	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.

35

---

Table of Contents

	The HM Capital Investors own a 60.3% limited partner interest in us and 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.

	•     neither our partnership agreement nor any other agreement requires the HM Capital 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 HM Capital Investors, in resolving conflicts of interest;
	•     the HM Capital 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;

36

---

Table of Contents

	•     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.

	The HM Capital Investors and their affiliates may compete directly with us.

	Our reimbursement of our general partner’s 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.

	•     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;
	•     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

37

---

Table of Contents

	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.

	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.

38

---

Table of Contents

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

	•     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.

	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.

	•     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.

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

39

---

Table of Contents

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

	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.

40

---

Table of Contents

	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.

	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, which could adversely affect the value of the common units.

41

---

Table of Contents

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

42

---

Table of Contents

ITEM 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Price Range

Cash

Period

High

Low

Distribution

Fiscal Year 2006

First Quarter (through March 15, 2006)*

$

21.29

$

19.47

**

*	Trading in common units on the NASDAQ National Market commenced on February 3, 2006.

**	The initial quarterly cash distribution is not due to be declared and paid until May 15, 2006.

	Cash Distribution Policy

	•     provide for the proper conduct of our business;
	•     comply with applicable law or any partnership debt instrument or other agreement; or
	•     provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

43

---

Table of Contents

	•	To replenish all, or approximately $48.0 million, of the working capital, or 18.7% of the net proceeds, $37.0 million of which was used to repay working capital borrowings under the revolving portion of our second amended and restated credit facility, that was distributed to the HM Capital Investors by RGS, immediately prior to consummation of the offering and the related formation transactions;
	•	to distribute approximately $195.5 million, or 76.1% of net proceeds, to the HM Capital Investors for reimbursement of capital expenditures comprising most of the initial investment by the HM Capital Investors in Regency Gas Services LLC;
	•	to pay $9.0 million, or 3.5% of net proceeds, to an affiliate of HM Capital as consideration for the termination of ten-year financial advisory and monitoring and oversight agreements between the affiliate of HM Capital and us; and
	•	to pay approximately $4.5 million, or 1.8% of net proceeds, of expenses associated with the offering and related formation transactions.

44

---

Table of Contents

(a)

(b)

(c)

Number of securities

remaining available for

Weighted-average

future issuance under

Number of securities to be

exercise price of

equity compensation

issued upon exercise of

outstanding

plans (excluding

outstanding options,

options, warrants

securities reported in

Plan Category

warrants and rights

and rights

column (a))

Equity compensation plans approved by security holders

0

n/a

0

Equity compensation plans not approved by security holders

0

n/a

2,865,584

Total

0

n/a

2,865,584

45

---

Table of Contents

	•	Regency LLC Predecessor 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 LLC Predecessor 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 HM Capital 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 amount of debt we incurred in connection with the acquisition increased our interest expense subsequent to December 1, 2004.
	•	After our acquisition by the HM Capital Investors, we initiated a risk management program comprised of commodity swaps and crude oil puts that we accounted for using mark-to-market accounting from December 2004 through June 2005. Under mark-to market accounting, changes in the fair value of these instruments are recorded in earnings. On July 1, 2005 we implemented hedge accounting for our derivative financial instruments that qualified, in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Changes in the fair value of these qualifying instruments, to the extent they are effective, are recorded in Other Comprehensive Income.
	•	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 320 miles from 200 miles. The total cost of the project, which was completed in December 2005, is approximately $157.0 million.

46

---

Table of Contents

						Regency Gas Services LLC									Regency LLC Predecessor
										Period from
										Acquisition
										Date					Period from				Period from
										(December 1,					January 1,				Inception
						Year Ended				2004) to					2004 to				(April 2, 2003) to
						December 31,				December 31,					November 30,				December 31,
						2005				2004					2004				2003
						($ in thousands)
Statement of Operations Data:
Total revenue (1)						$	692,603			$	47,841				$	432,321			$	186,533
	Expense
		Total cost of sales					620,751				40,986					362,762				163,461
		Operating expenses					21,812				1,819					17,786				7,012
		General and administrative					14,412				638					6,571				2,651
		Transaction expenses					—				—					7,003				724
		Depreciation and amortization					22,010				1,613					10,129				4,324
			Total operating expenses				678,985				45,056					404,251				178,172
	Operating income						13,618				2,785					28,070				8,361
	Other income and deductions
		Interest expense, net					(17,432	)			(1,335	)				(5,097	)			(2,392	)
		Loss on debt refinancing					(8,480	)			—					(3,022	)			—
		Other income and deductions, net					338				14					186				205
			Total other income and deductions				(25,574	)			(1,321	)				(7,933	)			(2,187	)
	Net (loss) income from continuing operations						(11,956	)			1,464					20,137				6,174
	Discontinued operations						732				—					(121	)			—
	Net (loss) income					$	(11,224	)		$	1,464				$	20,016			$	6,174
	Balance Sheet Data (at period end):
	Property, plant and equipment, net					$	480,583			$	328,348								$	118,986
	Total assets						654,324				486,489									164,330
	Long-term debt						358,350				250,000									66,600
	Member interest						169,778				176,964									59,856
	Cash Flow Data:
	Net cash flows provided by (used in):
		Operating activities				$	31,021			$	(4,930	)			$	32,401			$	6,494
		Investing activities					(150,195	)			(129,947	)				(84,721	)			(123,165	)
		Financing activities					119,571				132,515					56,380				118,245
	Other Financial Data:
	Total segment margin(1)					$	71,852			$	6,855				$	69,559			$	23,072
	EBITDA(1)						28,218				4,412					35,242				12,890
	Maintenance capital expenditures						7,817				358					5,548				1,633
	Segment Financial and Operating Data:
		Gathering and Processing Segment:
			Financial data:
				Segment margin(1)		$	56,179			$	6,247				$	61,347			$	18,805
				Segment operating expenses			19,883				1,655					16,230				6,131
			Operating data:
				Natural gas throughput (thousand MMBtu/d)			308				315					303				211
				NGL gross production (Bbls/d)			14,312				15,675					14,487				9,434
		Transportation Segment:
			Financial data:
				Segment margin		$	15,672			$	608				$	8,212			$	4,268
				Segment operating expenses			1,929				164					1,556				881
			Operating data:
				Throughput (thousand MMBtu/d)			258				162					192				212

47

---

Table of Contents

	•	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.

48

---

Table of Contents

				Regency Gas Services LLC									Regency LLC Predecessor
								Period from
								Acquisition
								Date					Period from				Period from
								(December 1,					January 1,				Inception
				Year Ended				2004) to					2004 to				(April 2, 2003) to
				December 31,				December 31,					November 30,				December 31,
				2005				2004					2004				2003
				($ in thousands)
Reconciliation of “EBITDA” to net cash flows provided by (used in) operating activities and to net (loss) income
Net cash flows provided by (used in) operating activities				$	31,021			$	(4,930	)			$	32,401			$	6,494
	Add (deduct):
		Depreciation and amortization			(23,092	)			(1,745	)				(10,461	)			(4,658	)
		Loss on debt refinancing			(8,480	)			—					(3,022	)			—
		Risk management portfolio value changes			(11,191	)			322					—				—
		Gain on the sale of Regency Gas Treating LP assets			626				—					—				—
		Gain on the sale of NGL line pack			628				—					—				—
		Accounts receivable			29,567				(2,583	)				20,408				31,390
		Advances to affiliates			—				—					(576	)			576
		Other current assets			1,237				2,430					1,169				1,070
		Accounts payable and accrued liabilities			(32,722	)			155					(18,122	)			(26,880	)
		Accrued taxes payable			(806	)			921					(1,475	)			(906	)
		Interest payable			(67	)			541					(398	)			(143	)
		Distributions payable			—				—					69				(68	)
		Other current liabilities			(1,208	)			(293	)				(173	)			(706	)
		Other assets			3,263				6,646					196				5
Net (loss) income				$	(11,224	)		$	1,464				$	20,016			$	6,174
	Add:
		Interest expense, net			17,432				1,335					5,097				2,392
		Depreciation and amortization			22,010				1,613					10,129				4,324
EBITDA(1)				$	28,218			$	4,412				$	35,242			$	12,890
Reconciliation of “total segment margin” to net (loss) income
Net (loss) income				$	(11,224	)		$	1,464				$	20,016			$	6,174
	Add (deduct):
		Operating expenses			21,812				1,819					17,786				7,012
		General and administrative			14,412				638					6,571				2,651
		Transaction expenses			—				—					7,003				724
		Depreciation and amortization			22,010				1,613					10,129				4,324
		Interest expense, net			17,432				1,335					5,097				2,392
		Loss on debt refinancing			8,480				—					3,022				—
		Other income and deductions, net			(338	)			(14	)				(186	)			(205	)
		Discontinued operations			(732	)			—					121				—
Total segment margin(1)				$	71,852			$	6,855				$	69,559			$	23,072

49

---

Table of Contents

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation

50

---

Table of Contents

	•	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.

	•	Gathering and Processing in which we provide “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 in which we deliver natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project. Our Transportation Segment includes certain marketing activities related to our transportation pipelines that are conducted by a separate subsidiary.

51

---

Table of Contents

	•	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 in commodity prices, however, 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 higher commodity price environments. For the year ended December 31, 2005, these arrangements accounted for about 25% 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 it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement 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 year ended December 31, 2005, these arrangements accounted for about 49% 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) provisions 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, (3) fixed cash fees for ancillary services, such as gathering, treating, and compression, or (4) the ability to bypass in unfavorable price environments. For the year ended December 31, 2005, these arrangements accounted for approximately 26% of our natural gas volumes for this segment.

52

---

Table of Contents

	•	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.

53

---

Table of Contents

	•	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.

54

---

Table of Contents

55

---

Table of Contents

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

	Formation of Regency Gas Services LLC

56

---

Table of Contents

	Acquisition of El Paso Assets

	Acquisition of Duke Energy Field Services Assets

	•	Regency LLC Predecessor 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 LLC Predecessor 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 HM Capital 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

57

---

Table of Contents

		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 and the pipeline, as expanded and extended, began operations on December 28, 2005. As of March 30, 2006 we were transporting approximately 450,000 MMBtu/d of natural gas.

58

---

Table of Contents

59

---

Table of Contents

60

---

Table of Contents

						Regency LLC
		Predecessor				Predecessor
		Year Ended
		December 31,
		2005				2004(d)				$ Change				% Change
						(combined)
		($ in millions)
Revenues(a)		$	692.6			$	480.2			$	212.4				44	%
Cost of sales			620.7				403.8				216.9				54
Total segment margin(b)			71.9				76.4				(4.5	)			(6	)
Operating expenses			21.8				19.6				2.2				11
General and administrative			14.4				7.2				7.2				100
Transaction expenses			-				7.0				(7.0	)			(100	)
Depreciation and amortization			22.0				11.7				10.3				88
Operating income			13.7				30.9				(17.2	)			(56	)
Interest expense, net			(17.4	)			(6.5	)			(10.9	)			168
Loss on debt refinancing			(8.5	)			(3.0	)			(5.5	)			183
Other income and deductions, net			0.3				0.2				0.1				50
Net (loss) income from continuing operations			(11.9	)			21.6				(33.5	)			(155	)
Discontinued operations			0.7				(0.1	)			0.8				(800	)
Net (loss) income		$	(11.2	)		$	21.5			$	(32.7	)			(152	)%
System inlet volumes (MMBtu/d)(c)			565,991				493,956				72,035.0				15	%
Processing volumes (MMBtu/d)			220,500				271,555				(51,055.0	)			(19	)

(a)		Includes $0.3 million of net unrealized gains on hedging transactions for the year ended December 31, 2004. Includes $9.5 million of net unrealized losses on hedging transactions and $2.0 million of put option expiration for the year ended December 31, 2005.
(b)		For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Financial Data.”
(c)		System inlet volumes include total volumes taken into our gathering and processing and transportation systems.
(d)		We combined the results of operations for the period from acquisition date (December 1, 2004) of the Predecessor and the period from January 1, 2004 to November 30, 2004 of the Regency LLC Predecessor to provide an annual reporting period for a more meaningful comparison versus the year ended December 31, 2005. To the extent operations for the 2005 period are not comparable to the combined 2004 period; we have disclosed such differences in the discussion of results of operations. See the separate discussion of the one month ended December 31, 2004.

61

---

Table of Contents

									Regency LLC
					Predecessor				Predecessor
					Year Ended
					December 31,
					2005				2004(b)				$ Change				% Change
									(combined)
					($ in millions)
Segment Financial and Operating Data:
	Gathering and Processing Segment
		Financial data:
			Segment Margin(a)		$	56.2			$	67.6			$	(11.4	)			(17	)%
			Operating expenses			19.9				17.9				2.0				11
		Operating data:
			Throughput (thousand MMBtu/d)			308				304				4.0				1
			NGL gross production (Bbls/d)			14,312				14,588				(276.0	)			(2	)
	Transportation Segment
		Financial data:
			Segment Margin		$	15.7			$	8.8			$	6.9				78	%
			Operating expenses			1.9				1.7				0.2				12
		Operating data:
			Throughput (thousand MMBtu/d)			258				190				68.0				36

(a)		Includes $0.3 million of net unrealized gains on hedging transactions for the year ended December 31, 2004. Includes $9.5 million of net unrealized losses on hedging transactions and $2.0 million of put option expiration for the year ended December 31, 2005.
(b)		We combined the results of operations for the period from acquisition date (December 1, 2004) of the Predecessor and the period from January 1, 2004 to November 30, 2004 of the Regency LLC Predecessor to provide an annual reporting period for a more meaningful comparison versus the year ended December 31, 2005. To the extent operations for the 2005 period are not comparable to the combined 2004 period, we have disclosed such differences in the discussion of results of operations. See the separate discussion of the one month ended December 31, 2004.

62

---

Table of Contents

	•	Pricing effects were negligible, as $10.8 million of increased segment margin attributable to higher commodity prices was offset by $10.8 million in cash hedge settlements,
	•	$0.3 million of increase segment margin attributable to increased pipeline throughput volumes,
	•	$11.5 million of decreased segment margin attributable to non-cash losses reflecting the net change in the fair value of derivatives contracts during the first six months of 2005 and the expiration of certain crude oil put option in 2005, and
	•	Segment margin in 2004 was increased by $0.3 million of non-cash gains reflecting the net change in the fair value of derivative contracts for the period.

63

---

Table of Contents

64

---

Table of Contents

						Regency LLC
		Regency LLC				Predecessor
		Predecessor
						Period from
		Period from				Inception
		January 1, 2004				(April 2, 2003)
		to November 30,				to December 31,
		2004				2003				$ Change				% Change
		($ in millions)
Revenues		$	432.3			$	186.5			$	245.8				132	%
Cost of sales			362.7				163.4				199.3				122
Total segment margin(a)			69.6				23.1				46.5				201
Operating expenses			17.8				7.0				10.8				154
General and administrative			6.6				2.7				3.9				144
Transaction expenses			7.0				0.7				6.3				900
Depreciation and amortization			10.1				4.3				5.8				135
Operating income			28.1				8.4				19.7				235
Interest expense, net			(5.1	)			(2.4	)			(2.7	)			113
Loss on debt refinancing			(3.0	)			—				(3.0	)			n/m
Other income and deductions, net			0.1				0.2				(0.1	)			(50	)
Net income from continuing operations			20.1				6.2				13.9				224
Discontinued operations			(0.1	)			—				(0.1	)			n/m
Net income		$	20.0			$	6.2			$	13.8				223	%
System inlet volumes (MMBtu/d)(b)			495,581				423,043				72,538				17	%
Processing volumes (MMBtu/d)			237,247				136,127				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 “Selected Financial Data.”
(b)		System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

65

---

Table of Contents

					Regency LLC				Regency LLC
					Predecessor				Predecessor
					Period from				Period from
					January 1,				Inception
					2004				(April 2, 2003)
					to November 30,				to December 31,
					2004				2003				$ Change				% Change
					($ in millions)
Segment Financial and Operating Data:
	Gathering and Processing Segment
		Financial data:
			Segment Margin		$	61.4			$	18.9			$	42.5				225	%
			Operating expenses			16.2				6.1				10.1				166
		Operating data:
			Throughput (thousand MMBtu/d)			303				211				92				44
			NGL gross production (Bbls/d)			14,487				9,434				5,053				54
	Transportation Segment
		Financial data:
			Segment Margin		$	8.2			$	4.2			$	4.0				95	%
			Operating expenses			1.6				0.9				0.7				78
		Operating data:
			Throughput (thousand MMBtu/d)			192				212				(20	)			(9	)

	•	$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;

66

---

Table of Contents

	•	$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.

	•	$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.

	•	$2.4 million was attributable to operation of the north Louisiana and mid-continent 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.

67

---

Table of Contents

68

---

Table of Contents

	•	cash generated from operations;
	•	borrowings under our credit facilities;
	•	debt offerings; and
	•	issuance of additional partnership units.

	•	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 acquisition of the Waha assets 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 HM Capital 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
	•	construction of our Regency Intrastate Enhancement Project at an estimated cost of $157 million, which began in May 2005 and was financed through cash flows from operations, long-term debt and a $15 million equity contribution.

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

69

---

Table of Contents

	•	a $18.7 million decrease in the net of accounts receivable and accounts payable. This change is primarily attributable to a $21.4 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 a $15 million equity contribution. The decrease is partially offset by the payment in February 2005 of a post-closing adjustment payment to our former owners in the amount of $5.8 million.
	•	a $12.3 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 in part by a $2.0 million decrease in current portion of long-term debt, due to our second amended credit facility, which no longer requires scheduled principal payments.

70

---

Table of Contents

	•	$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.

	•	$151.5 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 HM Capital Investors partially offset by;
	•	$6.0 million of proceeds from the sale of Cardinal assets; and
	•	$1.1 million of proceeds from the sale of NGL line pack.

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

71

---

Table of Contents

	•	$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.

	•	$250.0 million in proceeds of borrowings under our credit agreement which was established for our acquisition by the HM Capital Investors;
	•	$114.5 million of repayments of principal under credit agreements terminated as part of the acquisition by the HM Capital 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.

	•	$60.0 million in proceeds of borrowings under the term loan provisions of our credit facility;
	•	$15.0 million in equity contributions from the HM Capital Investors;
	•	$50.0 million in proceeds and repayments of borrowings under our revolving credit facility;
	•	$3.8 million in debt issuance costs related to amendments to our credit facility;
	•	$1.6 million in scheduled repayments of borrowings under our term loan credit facility.

	•	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.

72

---

Table of Contents

73

---

Table of Contents

	•	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;
	•	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.

74

---

Table of Contents

		Payments Due by Period
Contractual Obligations		Total				2006				2007-2008				2009-2010				Thereafter
Long-term Debt (including interest)(1)		$	483.5			$	24.6			$	51.5			$	407.4			$	-
Operating Leases			1.5				0.5				0.9				0.1				-
Purchase Obligations(2)(3)(4)			3.8				3.8				-				-				-
Total Contractual Obligations		$	488.8			$	28.9			$	52.4			$	407.5			$	-

(1)	Assumes a current LIBOR interest rate of 4.53% plus the applicable margin, which remains constant in all periods. The contractual obligations also include the effect of interest rate hedges on a notional amount of $200 million through March 2009.
(2)	Represents the purchase obligation for a pipeline project in north Louisiana.
(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 an estimated $4.5 million and $1.5 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.

75

---

Table of Contents

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

76

---

Table of Contents

							Notional
							Volume								We				Fair Value
Period			Commodity				(MBbls)				We Pay				Receive ($/gallon)				(Thousands)
Jan. 2006 - Dec 2007				Ethane				929				Index			$	0.55 to $0.58			$	(4,529	)
Jan. 2006 - Dec 2007				Propane				811				Index			$	0.66 to $0.825				(7,937	)
Jan. 2006 - Dec 2007				Butane				427				Index			$	1.02 to $1.085				(3,076	)
Jan. 2006 - Dec 2007				Natural
				Gasoline				164				Index			$	1.22 to $1.26				(665	)
	Total Fair Value																		$	(16,207	)

Notional

Volume

Strike

Fair Value

Period

Commodity

(MBbls)

Prices ($/Bbl)

(Thousands)

NYMEX West Texas

Jan. 2006 - Dec 2007

Intermediate Crude

2,438

$

30.00 to $36.50

$

575

		$ 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			2.7
Unrealized mark-to-market valuations of positions held at December 31, 2005			0.6
Effective portion of hedges included within Other Comprehensive Income			(11.0	)
Other*			(1.2	)
Balance of Net Risk Management Liability at December 31, 2005		$	(13.2	)

*	The amounts reported as “other” represents the expiration of options for which premiums were paid in prior periods.

77

---

Table of Contents

78

---

Table of Contents

79

---

Table of Contents

80

---

Table of Contents

81

---

Table of Contents

82

---

Table of Contents

Name		Age				Position with Regency GP LLC
James W. Hunt(1)(4)(5)			62			Chairman of the Board, President and Chief Executive Officer
Michael L. Williams			46			Executive Vice President and Chief Operating Officer
Stephen L. Arata			40			Executive Vice President and Chief Financial Officer
William E. Joor III			66			Executive Vice President, Chief Legal and Administrative Officer and Secretary
Charles M. Davis, Jr.(7)			44			Senior Vice-President-Corporate Development
Durell J. Johnson			43			Vice President, Operations and Engineering
Lawrence B. Connors			55			Vice President, Finance and Chief Accounting Officer
Alvin Suggs			53			Vice President and General Counsel
Joe Colonnetta(1)(4)(6)			44			Director
Jason H. Downie(1)(4)(5)(6)			35			Director
A. Dean Fuller(2)(3)			58			Director
Jack D. Furst			47			Director
J. Edward Herring(2)(6)			35			Director
Robert D. Kincaid(2)			45			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.
(7)	Mr. Davis was elected an officer on March 21, 2006 and commenced employment in March 2006.

83

---

Table of Contents

84

---

Table of Contents

85

---

Table of Contents

86

---

Table of Contents

			Annual								Long-Term								All Other
			Compensation								Compensation								Compensation
			Annual								Restricted
			Salary and				Other				Common				Underlying
			Bonuses				Compensation				Units				Options
Name and Principal Position			($) (1)				($) (2)(3)				($)				(Units)
James W. Hunt			$	246,000			$	4,200				—				100,000				—
	President, Chief Executive Officer and Chairman of the Board
Michael L. Williams				215,250				3,675				—				40,000				—
	Executive Vice President and Chief Operating Officer
Stephen L. Arata				205,000				—				—				35,000				—
	Executive Vice President and Chief Financial Officer
William E. Joor III				205,000				3,500				—				35,000				—
	Executive Vice President and Chief Legal and Administrative Officer
Alvin Suggs				184,500				2,700				—				15,000				—
	Vice President and General Counsel

(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. Regency GP LLC has adopted and continued 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 considered a number of factors, including annual personal and company performance goals. These amounts include small advances of the bonuses that were awarded in March 2006 but paid as Christmas bonuses in December 2005. The amount of the March 2006 awards not included in the above table are as follows: Mr. Hunt — $134,583; Mr. Williams — $117,760; Mr. Arata — $63,339; Mr. Joor — $94,580; Mr. Suggs — $95,500. Upon the completion of our initial public offering in February 2006, the board of directors of Regency GP LLC 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 the initial public offering to December 31, 2006.
(2)	These amounts include the contributions of Regency Gas Services LLC to our Section 401(k) plan for the entire year.
(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.

87

---

Table of Contents

(4)	Regency GP LLC has adopted a Long Term Incentive Plan. Please read the description of the plan under “— Long Term Incentive Plan.”
(5)	All options have an exercise price of $20 per unit (equal to the initial public offering price) and vest and may be exercised in one-third increments on the anniversary of the grant date over a period of three years.

	•	each person who then owned 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.

	•	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 the IPO for common and subordinated units.

88

---

Table of Contents

						Percentage of								Percentage of
						Outstanding								Outstanding				Percentage
		Common				Common				Subordinated				Subordinated				of Total
Name of Beneficial Owner		Units				Units(7)				Units				Units(7)				Units
Regency Acquisition LP(1)			3,456,255				18.1	%			16,699,462				87.4	%			52.8	%
John R. Muse(1)			3,506,255				18.4				16,699,462				87.4				52.9
James W. Hunt(2)(3)(5)			73,993				0.4				840,678				4.4				2.4
Michael L. Williams(2)(3)(5)			99,425				0.5				480,387				2.5				1.5
Stephen L. Arata(2)(3)(5)			49,712				0.3				240,194				1.3				0.8
William E. Joor III(2)(3)(5)			74,569				0.4				360,290				1.9				1.1
Durell J. Johnson(2)(3)(5)			14,914				0.1				72,058				0.4				0.2
Lawrence B. Connors(2)(3)(5)			14,914				0.1				72,058				0.4				0.2
Alvin Suggs(2)(3)(5)			14,914				0.1				72,058				0.4				0.2
Charles M. Davis Jr.(6)			100,000				0.5				0				0.0				0.3
Joe Colonnetta(1)			25,000				0.1				0				0.0				0.1
Jason H. Downie(1)			11,000				0.1				0				0.0				Note(8	)
A. Dean Fuller			12,500				0.1				0				0.0				Note(8	)
Jack D. Furst(1)			12,500				0.1				0				0.0				Note(8	)
J. Edward Herring(1)			10,000				0.1				0				0.0				Note(8	)
Robert D. Kincaid(4)(5)			12,715				0.1				37,278				0.2				0.1
Gary W. Luce(4)(5)			12,715				0.1				37,278				0.2				0.1
J. Otis Winters			10,000				0.1				0				0.0				Note(8	)
Robert W. Shower			10,000				0.1				0				0.0				Note(8	)
All directors and executive Officers as a group (16 persons)			4,015,126				21.0	%			18,911,741				99.0	%			60.0	%

(1)	According to Schedule 13D/ A (“Amendment No. 1”) dated March 8, 2004 (the “Schedule 13D”) filed jointly by Regency Acquisition LP, a Delaware limited partnership (“Acquisition”); Regency Holdings LLC, a Delaware limited liability company and the general partner of Acquisition (“Holdings”); HMTF Regency, L.P., a Delaware limited partnership which is the sole member of Holdings and owns all of the limited partnership interest in Acquisition (“HMTF Regency”); HMTF Regency, L.L.C., a Texas limited liability company and the general partner of HMTF Regency (“HMTF GP”); Hicks, Muse, Tate & Furst Equity Fund V, L.P., a Delaware limited partnership and the sole member of HMTF GP (“Fund V”); HM5/ GP LLC, a Texas limited liability company, the general partner of Fund V (“HM5”); and John R. Muse, a member and the sole manager of HM5 (“Muse” and, together with Acquisition, Holdings, HMTF Regency, HMTF GP, Fund V and the General Partner (collectively, the “HMTF Entities”), the “13D Parties”). Acquisition is the record and beneficial owner of 3,456,255 common units and 16,699,462 subordinated units. As a result of Muse being the sole manager of the HM5 and the relationship of HM5 to Fund V, Fund V to HMTF GP, HMTF GP to HMTF Regency, HMTF Regency to Holdings, and Holdings to Acquisition, each 13D Party may be deemed to have shared power to vote, or direct the disposition of, and to dispose, or direct the disposition of, the common units and subordinated units held of record by Acquisition. Muse also is the record owner of 50,000 common units and has sole power to vote or direct the vote and the power to dispose or direct the disposition of the common units owned of record by him. Each of the HMTF Entities disclaims beneficial ownership of the common units held of record by Muse.
(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 — 18,817 common and 90,920 subordinated; Mr. Williams — 4,897 common and 23,659 subordinated; Mr. Arata — 4,897 common and 23,659 subordinated; Mr. Joor — 4,897 common and 23,659 subordinated; Mr. Johnson — 1,959 common and 9,464 subordinated; Mr. Connors — 4,897 common and 23,659 subordinated; and Mr. Suggs — 1,959 common and 9,464 subordinated. Each of these executive officers will be treated as regards his ownership of Class A Units, in the same manner as any other HM Capital 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 were 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.”

89

---

Table of Contents

(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 — 4,897 common and 23,659 subordinated; and Mr. Kincaid — 4,897 common and 23,659 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.
(5)	At the time of consummation of our initial public offering, each of these individuals exchanged Class B or Class D Units in HMTF Regency, L.P. for common and subordinated units as described in note (3) and for Class E Units of HMTF Regency, L.P. The Class E Units evidence the pecuniary interests of the holders in the general partner interest in our General Partner, Regency GP LP, owned indirectly by HMTF Regency, L.P. As a result of their holdings of both Class A and Class E Units in HMTF Regency, L.P., the following named individuals own the indicated percentages of undivided general partner interest in our General Partner: Mr. Hunt — 3.2%; Mr. Williams — 1.6%; Mr. Joor — 1.3%; Mr. Arata — 0.9%; Mr. Connors — 0.4%; Mr. Johnson — 0.3%; Mr. Suggs — 0.3%; Mr. Kincaid — 0.2%; Mr. Luce — 0.2%.
(6)	Mr. Davis was elected an officer on March 21, 2006 and commenced employment in March 2006.
(7)	The number of Common and Subordinated units outstanding are 19,103,896 each.
(8)	Ownership percentages are less than .1%.

ITEM 13.	Certain Relationships and Related Transactions

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

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 3,953,896 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.

90

---

Table of Contents

		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 $32.3 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 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		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

91

---

Table of Contents

	•     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 the IPO; and
	•     certain income tax liabilities attributable to the operation for the assets contributed to us prior to the time they were contributed.

	Amendments

	Competition

92

---

Table of Contents

	•     The total number of common and subordinated units and general partner interests issued or transferred to HMTF Regency, L.P. were valued at the initial offering price per common unit ($20.00).
	•     From that aggregate number of units and interests, a number of units and interests with an equivalent value of $320.6 million (representing a 150% return on the aggregate investment in Class A Units plus transaction expenses) were allocated to the Class A Unit holders.
	•     Of the remainder, 87.5% were allocated to the Class A Unit holders and 12.5% were allocated to the Class B Unit holders as a group.
	•     The common and subordinated units allocated to the holders of Class A Units will continue to be held by HMTF Regency, L.P.
	•     The common and subordinated units allocated to the holders of Class B Units were 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 were allocated among the group in accordance with their respective holdings of Class B Units.

93

---

Table of Contents

94

---

Table of Contents

ITEM 14.	Principal Accounting Fees and Services

		December 31,
		2005				2004
Audit fees(1)		$	1,180,000			$	234,000
Audit related fees(2)			60,000				—
Tax fees(3)			53,000				164,000
All other fees(4)			—				—
Total		$	1,293,000			$	398,000

(1)	Includes fees for audits of annual financial statements of our companies (as well as an audit of our financial statements at June 30, 2005 in connection with our initial public offering), reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the Securities and Exchange Commission.
(2)	Includes fees related to consultations concerning financial accounting and reporting standards and services related to the implementation of our internal controls over financial reporting.
(3)	Includes fees related to professional services for tax compliance, tax advice, and tax planning. These tax services were incurred on behalf of HMTF Regency, L.P. for the years ended December 31, 2004 and 2005.
(4)	Consists of fees for services other than services reported above.

	•	the auditors’ internal quality-control procedures;
	•	any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
	•	the independence of the external auditors;
	•	the aggregate fees billed by our external auditors for each of the previous two fiscal years; and
	•	the rotation of the lead partner.

95

---

Table of Contents

ITEM 15.	Exhibits, Financial Statement Schedules.

96

---

Table of Contents

	REGENCY ENERGY PARTNERS LP

	By:	REGENCY GP LP, its general

	partner

	By:	REGENCY GP LLC, its general

	partner

	By:	/s/ James W. Hunt

	James W. Hunt
	Chief Executive Officer and officer duly
	authorized to sign on behalf of the registrant

				Title		Date
Signature
/s/ James W. Hunt James W. Hunt				Chairman, President, and Chief Executive Officer (Principal Executive Officer)		March 30, 2006
/s/ Stephen L. Arata Stephen L. Arata				Executive Vice President and Chief Financial Officer (Principal Financial Officer)		March 30, 2006
/s/ Lawrence B. Connors Lawrence B. Connors				Vice President, Finance and Accounting (Principal Accounting Officer)		March 30, 2006
/s/ Joe Colonnetta Joe Colonnetta				Director		March 30, 2006
/s/ Jason H. Downie Jason H. Downie				Director		March 30, 2006
/s/ A. Dean Fuller A. Dean Fuller				Director		March 30, 2006
/s/ Jack D. Furst Jack D. Furst				Director		March 30, 2006
/s/ J. Edward Herring J. Edward Herring				Director		March 30, 2006

97

---

Table of Contents

				Title		Date
Signature
/s/ Robert D. Kincaid Robert D. Kincaid				Director		March 30, 2006
/s/ Gary W. Luce Gary W. Luce				Director		March 30, 2006
/s/ Robert W. Shower Robert W. Shower				Director		March 30, 2006
/s/ J. Otis Winters J. Otis Winters				Director		March 30, 2006

98

---

Table of Contents

Exhibit
Number						Description
	3.1*			—		Certificate of Limited Partnership of Regency Energy Partners LP
	3.2*			—		Form of Amended and Restated Limited Partnership Agreement of Regency Energy Partners LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3.3*			—		Certificate of Formation of Regency GP LLC
	3.4*			—		Form of Amended and Restated Limited Liability Company Agreement of Regency GP LLC
	3.5*			—		Certificate of Limited Partnership of Regency GP LP
	3.6*			—		Form of Amended and Restated Limited Partnership Agreement of Regency GP LP
	4.1*			—		Form of Common Unit Certificate
	10.1*			—		Amended and Restated Credit Agreement of Regency Gas Services LLC
	10.2*			—		Amended and Restated Second Lien Credit Agreement of Regency Gas Services LLC
	10.3*			—		Second Amended and Restated Credit Agreement of Regency Gas Services LLC
	10.4*			—		Regency GP LLC Long-Term Incentive Plan
	10.5*			—		Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan — Unit Option Grant
	10.6*			—		Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan — Restricted Unit Grant
	10.7*			—		Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan — Phantom Unit Grant (With DERS)
	10.8*			—		Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan — Phantom Unit Grant (Without DERS)
	10.9*			—		Form of Contribution, Conveyance and Assumption Agreement
	10.10*			—		Executive Employment Agreement dated December 1, 2004 between the Registrant and James W. Hunt
	10.11*			—		Employment Agreement dated December 1, 2004 between the Registrant and Michael L. Williams
	10.12*			—		Severance Agreement dated January 1, 2005 between the Registrant and William E. Joor, III
	10.13*			—		Purchase Agreement by and among Regency Acquisition LLC, Regency Services, LLC, Regency Gas Services LLC, the Members of Regency Services, LLC and the Partners of CB Offshore Equity Fund V — Holdings, L.P. dated October 21, 2004.
	10.14*			—		Purchase and Sale Agreement between Duke Energy Field Services, LP and Regency Gas Services Waha, LP Dated January 29, 2004
	10.15*			—		Pipeline Construction Contract between Regency Gas Services LLC and H.C. Price dated May 2, 2005 (relating to construction of 30” natural gas pipeline with facilities in Louisiana)
	10.16*			—		Pipeline Construction Contract between Regency Intrastate Gas LLC and H.C. Price Co. dated May 2nd, 2005 (relating to the construction of 24” natural gas pipeline with facilities in Louisiana)
	10.17*			—		Ground Lease Agreement (Lakin Plant)
	10.18*			—		Ground Lease Agreement (Mocane Plant)
	10.19*			—		Lisbon Lease Agreement
	10.20*†			—		Firm Transportation Agreement dated June 8, 2005 between Regency Intrastate Gas LLC and Anadarko Energy Services Company
	10.21*			—		Form of Third Amended and Restated Credit Agreement of Regency Gas Services LLC
	10.22*			—		Form of Indemnification Agreement between Regency GP LLC and Indemnitees
	10.23*			—		Financial Advisory Agreement

99

---

Table of Contents

Exhibit
Number						Description
	10.24*			—		Monitoring and Oversight Agreement
	10.25*			—		Form of Omnibus Agreement
	21.1*			—		List of Subsidiaries of Regency Energy Partners LP
	31.1			—		Certifications pursuant to Rule 13a-14(a).
	31.2					Certifications pursuant to Rule 13a-14(a).
	32.1					Certifications pursuant to Section 1350.
	32.2			—		Certifications pursuant to Section 1350.
	99.1			—		Financial Statements of Regency GP LP, the general partner of the registrant.
	*					Incorporated by reference to the comparably numbered exhibit to the registrant’s registration statement on Form S-1 (File No. 333-128332).
	†					Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

100

---

Table of Contents

Regency Energy Partners LP
Report of Independent Registered Public Accounting Firm			F-2
Balance Sheet at December 31, 2005			F-3
Notes to Financial Statements			F-4
Regency Gas Services LLC
Report of Independent Registered Public Accounting Firm			F-5
Consolidated Balance Sheets			F-6
Consolidated Statements of Operations			F-7
Consolidated Statement of Changes in Member Interest			F-8
Consolidated Statements of Cash Flows			F-9
Notes to Consolidated Financial Statements			F-10

F-1

---

Table of Contents

F-2

---

Table of Contents

		December 31, 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-3

---

Table of Contents

F-4

---

Table of Contents

F-5

---

Table of Contents

				Regency Gas Services LLC
				December 31,				December 31,
				2005				2004
ASSETS
Current Assets:
	Cash and cash equivalents			$	3,669			$	3,272
	Restricted cash				5,533				5,410
	Accounts receivable, net of allowance of $169 in 2005 and $135 in 2004				78,782				49,215
	Assets from risk management activities				1,717				2,767
	Other current assets				3,950				2,713
Total current assets					93,651				63,377
Property, plant and equipment
	Gas plants and buildings				46,399				44,606
	Gathering and transmission systems				397,481				250,392
	Other property, plant and equipment				41,470				20,427
	Construction-in-progress				16,738				14,380
		Total property, plant and equipment			502,088				329,805
	Less accumulated depreciation				(21,505	)			(1,457	)
Property, plant and equipment, net					480,583				328,348
Intangible and other assets
	Intangible assets, net of amortization				16,370				18,342
	Goodwill				57,552				58,529
	Assets held for sale				—				4,101
	Long-term assets from risk management activities				1,333				6,243
	Other, net of amortization on debt issuance costs of $271 in 2005 and $112 in 2004				4,835				7,549
Total intangible and other assets					80,090				94,764
TOTAL ASSETS				$	654,324			$	486,489
LIABILITIES & MEMBER INTEREST
Current Liabilities:
	Accounts payable and accrued liabilities			$	99,745			$	51,471
	Escrow payable				5,533				5,410
	Accrued taxes payable				2,266				1,460
	Interest payable				67				—
	Liabilities from risk management activities				11,312				14
	Current portion of long term debt				—				2,000
	Other current liabilities				2,378				1,170
Total current liabilities					121,301				61,525
Long term liabilities from risk management activities					4,895				—
Long-term debt					358,350				248,000
Commitments and contingencies
Member interest					169,778				176,964
TOTAL LIABILITIES & MEMBER INTEREST				$	654,324			$	486,489

F-6

---

Table of Contents

			Regency Gas Services LLC									Regency LLC Predecessor
							Period from
							Acquisition									Period from
							Date					Period from				Inception
							(December 1,					January 1,				(April 2,
			Year Ended				2004) to					2004 to				2003) to
			December 31,				December 31,					November 30,				December 31,
			2005				2004					2004				2003
REVENUE
Gas sales			$	495,987			$	32,616				$	279,582			$	127,149
NGL sales				179,305				11,890					123,827				46,697
Gathering, transportation and other fees				25,921				1,943					19,016				9,439
Unrealized/realized gain/(loss) from risk management activities				(22,243	)			322					—				—
Other				13,633				1,070					9,896				3,248
	Total revenue			692,603				47,841					432,321				186,533
EXPENSE
Cost of gas and liquids				611,137				39,979					352,508				158,524
Other cost of sales				9,614				1,007					10,254				4,937
Operating expenses				21,812				1,819					17,786				7,012
General and administrative				14,412				638					6,571				2,651
Transaction expenses				—				—					7,003				724
Depreciation and amortization				22,010				1,613					10,129				4,324
	Total operating expense			678,985				45,056					404,251				178,172
OPERATING INCOME				13,618				2,785					28,070				8,361
OTHER INCOME AND DEDUCTIONS
Interest expense, net				(17,432	)			(1,335	)				(5,097	)			(2,392	)
Loss on debt refinancing				(8,480	)			—					(3,022	)			—
Other income and deductions, net				338				14					186				205
	Total other income and deductions			(25,574	)			(1,321	)				(7,933	)			(2,187	)
NET (LOSS) INCOME FROM CONTINUING OPERATIONS				(11,956	)			1,464					20,137				6,174
DISCONTINUED OPERATIONS
Income (loss) from operations of Regency Gas Treating LP (including gain on disposal of $626 in 2005; Note 2)				732				—					(121	)			—
NET (LOSS) INCOME			$	(11,224	)		$	1,464				$	20,016			$	6,174

F-7

---

Table of Contents

								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 the HM Capital Investors			$	—							$	171,000
	Member interest contribution 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 interest contribution July 25, 2005												15,000
	Net loss for the year ended December 31, 2005				(11,224	)							(11,224	)
	Other Comprehensive Income (Loss):
		Net change in fair value of cash flow hedges			(16,502	)			(16,502	)
		Amounts reclassified to earnings during the period			5,540				5,540
	Other Comprehensive Loss				(10,962	)							(10,962	)
	Comprehensive Loss			$	(22,186	)
	Balance, December 31, 2005							$	(10,962	)		$	169,778

F-8

---

Table of Contents

					Regency Gas Services LLC								Regency LLC Predecessor
									Period from
									Acquisition Date				Period from				Period from
									(December 1,				January 1, 2004				Inception
					Year Ended				2004) to				to				(April 2, 2003) to
					December 31,				December 31,				November 30,				December 31,
					2005				2004				2004				2003
OPERATING ACTIVITIES
Net income (loss)					$	(11,224	)		$	1,464			$	20,016			$	6,174
Adjustments to reconcile net income to net cash flows provided (used) by operations:
	Depreciation & amortization					23,092				1,745				10,461				4,658
	Loss on debt refinancing					8,480				—				3,022				—
	Risk management portfolio valuation changes					11,191				(322	)			—				—
	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			(29,567	)			2,583				(20,408	)			(31,390	)
			Advances to affiliates			—				—				576				(576	)
			Other current assets			(1,237	)			(2,430	)			(1,169	)			(1,070	)
			Accounts payable and accrued liabilities			32,722				(155	)			18,122				26,880
			Accrued taxes payable			806				(921	)			1,475				906
			Interest payable			67				(541	)			398				143
			Distributions payable			—				—				(69	)			68
			Other current liabilities			1,208				293				173				706
		Other assets				(3,263	)			(6,646	)			(196	)			(5	)
Net cash flows provided (used) by operating activities						31,021				(4,930	)			32,401				6,494
INVESTING ACTIVITIES
	Capital expenditures					(151,486	)			(2,143	)			(15,092	)			(3,624	)
	Cash outflows for acquisition by HM Capital Investors					(5,808	)			(127,804	)			—				—
	Proceeds from sale of Regency Gas Treating LP assets					6,000				—				—				—
	Proceeds from sale of NGL line pack					1,099				—				—				—
	Purchase of El Paso properties					—				—				—				(119,541	)
	El Paso — escrow adjustment					—				—				1,168				—
	Cardinal acquisition					—				—				(3,533	)			—
	Purchase of Waha properties					—				—				(67,264	)			—
Net cash flows used in investing activities						(150,195	)			(129,947	)			(84,721	)			(123,165	)
FINANCING ACTIVITIES
	Borrowings under credit facilities					60,000				250,000				45,363				70,000
	Repayments under credit facilities					(1,650	)			(101,471	)			(10,492	)			(3,401	)
	Net borrowings under revolving credit facilities					50,000				(13,000	)			13,000				—
	Debt issuance costs					(3,779	)			(7,514	)			(1,491	)			(2,036	)
	Member interest contributions					15,000				4,500				10,000				53,750
	Member interest distributions					—				—				—				(68	)
Net cash flows provided by financing activities						119,571				132,515				56,380				118,245
Net increase (decrease) in cash and cash equivalents						397				(2,362	)			4,060				1,574
Cash and equivalents at beginning of period						3,272				5,634				1,574				—
Cash and equivalents at end of period					$	3,669			$	3,272			$	5,634			$	1,574
Supplemental cash flow information
		Interest paid, net of amounts capitalized			$	16.633			$	1,763			$	4,437			$	1,883
		Non-cash capital expenditures in accounts payable			$	21,360			$	(134	)		$	804			$	146

F-9

---

Table of Contents

1.	Organization, Business Operations and Summary of Significant Accounting Policies

F-10

---

Table of Contents

F-11

---

Table of Contents

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 (Regency LLC Predecessor)		$	4.3
January 1, 2004 to November 30, 2004 (Regency LLC Predecessor)			10.1
Acquisition date (December 1, 2004) to December 31, 2004			1.5
Year ended December 31, 2005			20.1

F-12

---

Table of Contents

										Regency Gas
		Gathering and								Treating LP
		Processing				Transportation				Discontinued
Goodwill		Segment				Segment				Operations				Total
		($ in millions)
Balance as of January 1, 2004 (Regency LLC Predecessor)		$	—			$	—			$	—			$	—
Goodwill recorded as a result of the HM Capital 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 December 31, 2005		$	23.4			$	34.2			$	—			$	57.6

		Predecessor				Predecessor
		December 31, 2005				December 31, 2004
		($ in millions)
Imbalance Receivables		$	1.5			$	0.9
Imbalance Payables		$	1.4			$	1.0

F-13

---

Table of Contents

F-14

---

Table of Contents

2.	Acquisitions and Dispositions

F-15

---

Table of Contents

		At
		December 1,
		2004
		($ in millions)
Current assets		$	66.8
Property, plant and equipment			332.0
Intangible assets, subject to amortization			18.5
Goodwill			58.5
Total assets acquired			475.8
Current liabilities			(55.8	)
Net assets acquired		$	420.0

										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 December 31, 2005			(0.9	)			(1.2	)			—				(2.1	)
Net carrying amount at December 31, 2005		$	11.0			$	5.3			$	—			$	16.3
Amortization for the year ended December 31, 2005		$	(0.8	)		$	(1.1	)		$	—			$	(1.9	)

For the year ending December 31,		Total
		($ in millions)
2006			1.9
2007			1.8
2008			1.2
2009			1.2
2010			1.2

	Regency Gas Treating LP

F-16

---

Table of Contents

						Predecessor
										Regency LLC
						Period from				Predecessor
						Acquisition
		Predecessor				Date				Period from
						(December 1,				January 1,
		Year Ended				2004) to				2004 to
		December 31,				December 31,				November 30,
		2005				2004				2004
		($ in millions)
Equipment lease revenue		$	0.3			$	0.1			$	0.5
Operating income (loss)			0.1				—				0.1
Net income (loss)			0.7				—				(0.1	)
Gain on disposal		$	0.6				—				—

	Waha

		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

F-17

---

Table of Contents

		Regency LLC Predecessor
						Period from
		Period from				Inception
		January 1, 2004 to				(April 2, 2003) to
		November 30,				December 31,
		2004				2003
		($ in millions)
Revenue		$	454.1			$	262.6
Net Income			21.1				10.0

	Mid-Continent and North Louisiana

		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

F-18

---

Table of Contents

3.	Long-Term Debt

			Predecessor				Predecessor
			December 31, 2005				December 31, 2004
			($ in millions)
Term Loans			$	308.4			$	250.0
Revolving Loans				50.0				—
	Less: Current Portion			—				(2.0	)
Long-term Debt			$	358.4			$	248.0
Total Facility Limit			$	468.4			$	290.0
	Term Loans			(308.4	)			(250.0	)
	Revolving Loans			(50.0	)			—
	Letters of Credit			(10.7	)			—
Credit Available			$	99.3			$	40.0

F-19

---

Table of Contents

										Applicable				Total Fixed
		Notional								Margin As of				Rate As of
		Amount								December 31,				December 31,
Period Covered		($ millions)				Fixed Pay				2005				2005
April 2005 to March 2007		$	125.0				3.715	%			2.250	%			5.965	%
August 2005 to March 2007			75.0				4.340				2.250				6.590	%
April 2007 to March 2009			200.0				4.610				2.250				6.860	%

F-20

---

Table of Contents

F-21

---

Table of Contents

4.	Fair Value of Financial Instruments

5.	Leases

For the Year Ended December 31,		Amount
		($ in millions)
2006		$	0.5
2007			0.5
2008			0.4
2009 and beyond			0.1
Total Minimum Lease Payments		$	1.5

6.	Commitments and Contingencies

F-22

---

Table of Contents

F-23

---

Table of Contents

7.	Related Party Transactions

	Prior to the HM Capital transaction

8.	Concentration Risk

F-24

---

Table of Contents

Predecessor

Regency LLC Predecessor

Period from

Acquisition

Date

Period from

Period from

Year

(December 1,

January 1,

Inception

Ended

2004) to

2004 to

(April 2, 2003)

December 31,

December 31,

November 30,

to December 31,

Customer

Reporting Segment

2005

2004

2004

2003

($ in millions)

Alabama Gas Corporation

Transportation

$

132.5

$

11.1

$

69.7

$

22.5

Koch Hydrocarbon, LP

Gathering and Processing

*

7.1

*

27.6

Atmos Energy Marketing, LLC

Gathering and Processing

76.1

5.8

*

*

Supplier		Reporting Segment
Cohort Energy Company			Transportation			$	93.2			$	6.8			$	55.0			$	28.6
KCS Energy, Inc.			Transportation				63.4				*				*				19.5
Chesapeake Energy Corporation			Transportation				75.4				3.8				*				*

*		Amounts are less than 10% of total Company revenues or cost of sales for the respective periods.

9.	Segment Information

F-25

---

Table of Contents

			Gathering and																Consolidated
			Processing				Transportation				Corporate				Eliminations				Total
			($ in millions)
External Revenue
	For the year ended December 31, 2005		$	488.9	(1)		$	203.7			$	—			$	—			$	692.6
	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 year ended December 31, 2005		$	—			$	57.1			$	—			$	(57.1	)		$	—
	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	)			—
Cost of Sales
	For the year ended December 31, 2005		$	432.7			$	188.0			$	—			$	—			$	620.7
	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 year ended December 31, 2005		$	56.2	(1)		$	15.7			$	—			$	—			$	71.9
	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 year ended December 31, 2005		$	19.9			$	1.9			$	—			$	—			$	21.8
	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 year ended December 31, 2005		$	16.8			$	4.7			$	0.5				—				22.0
	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
	December 31, 2005		$	342.6			$	292.0			$	19.7			$	—			$	654.3
	December 31, 2004			337.1				125.2				24.2				—				486.5
Expenditures for Long-Lived Assets
	For the year ended December 31, 2005		$	11.1			$	158.1			$	0.9			$	—			$	170.1
	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

	*	Regency LLC Predecessor

(1)	Includes $9.5 million of net unrealized losses on risk management activities and $2.0 million of non-cash put option expiration.

F-26

---

Table of Contents

			Predecessor								Regency LLC Predecessor
							Period from				Period from				Period from
							Acquisition Date				January 1,				Inception
			Year Ended				(December 1, 2004)				2004 to				(April 2, 2003) to
			December 31,				to December 31,				November 30,				December 31,
			2005				2004				2004				2003
			($ in millions)
Total Segment Margin (from above)(1)			$	71.9			$	6.8			$	69.6			$	23.1
Operating expenses				21.8				1.8				17.8				7.0
General and administrative				14.4				0.6				6.6				2.7
Transaction expenses				—				—				7.0				0.7
Depreciation and amortization				22.0				1.6				10.1				4.3
OPERATING INCOME				13.7				2.8				28.1				8.4
OTHER INCOME AND DEDUCTIONS
Interest expense, net				(17.4	)			(1.3	)			(5.1	)			(2.4	)
Loss on debt refinancing				(8.5	)			—				(3.0	)			—
Other income and deductions, net				0.3				—				0.1				0.2
	Total other income and deductions			(25.6	)			(1.3	)			(8.0	)			(2.2	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS			$	(11.9	)		$	1.5			$	20.1			$	6.2

(1)	Includes $9.5 million of net unrealized losses on risk management activities and $2.0 million of non-cash put option expiration in 2005.

F-27

---

Table of Contents

11.	Subsequent Event

12.	Quarterly Financial Data (Unaudited)

							Operating
			Operating				Income				Net Income
			Revenues				(Loss)				(Loss)
Quarter Ended
			($ in thousands)
2005:
	March 31		$	106,612			$	(12,064	)		$	(15,141	)
	June 30			137,350				10,757				6,482
	September 30			190,604				8,197				(3,901	)
	December 31			258,037				6,728				1,336
2004:
	March 31		$	94,991			$	5,987			$	3,450
	June 30			115,700				6,949				5,640
	September 30			128,415				13,099				11,452
	Month ended December 31			47,841				2,785				1,464
	Two months ended November 30 (Regency LLC Predecessor)			93,215				2,035				(526	)

F-28