8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report:  May 9, 2008

(Date of earliest event reported: Not Applicable)

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE	0001-51757	16-1731691
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1700 Pacific, Suite 2900

Dallas, Texas 75201

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (214) 750-1771

(Former name or former address, if changed since last report.): Not Applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

Item 8.01 Other Events

Item 9.01 Financial Statements and Exhibits

Exhibit Index

99.1- Selected Financial Data

99.2- Management’s Discussion and Analysis

99.3- Quantitative and Qualitative Disclosure about Market Risk

99.4- Consolidated Financial Statements

99.5- Ratio of Earnings to Fixed Charges

99.6- Consent of KPMG LLP

99.7- Consent of Deloitte & Touche LLP

ITEM 8.01 OTHER EVENTS

On January 7, 2008, the Partnership acquired all the outstanding equity of FrontStreet Hugoton, LLC (“FrontStreet Acquisition”) from ASC Hugoton LLC and FrontStreet EnergyOne LLC for the issuance of 4,701,034 Class E common units of the Partnership to ASC and the cash payment of $11,752,000 to EnergyOne, inclusive of a payment to terminate a management services agreement.  The Partnership financed the cash portion of the purchase price out of its revolving credit facility.  The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units were not entitled to participate in earnings or distributions of operating surplus by the Partnership.  The Class E common units converted into common units on a one-for-one basis on April 24, 2008.

FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.

Because the FrontStreet acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), the Partnership accounted for the acquisition in a manner similar to the pooling of interest method. Under this method of accounting, the Partnership will reflect historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities. Further, certain transaction costs that would normally be capitalized were expensed.

The Partnership has recast its financial statements to include the operations of FrontStreet from June 18, 2007 (the date upon which common control began) forward in this current report on Form 8-K.  The Partnership’s financial and operational data for periods ending prior to January 1, 2007 are not different from the information previously disclosed in the Partnership’s December 31, 2007 Form 10-K.

Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in an historical context, refer to Regency Energy Partners LP, or the Partnership, and to Regency Gas Services LLC, all the outstanding member interests of which were contributed to the Partnership on February 3, 2006, and its subsidiaries.  When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries.  We use the following definitions in this current report on Form 8-K:

Name	Definition or Description
ASC	ASC Hugoton LLC, an affiliate of GECC
BBE	BlackBrush Energy, Inc.
Bbls/d	Barrels per day
BBOG	BlackBrush Oil & Gas, LP
Bcf	One billion cubic feet
Bcf/d	One billion cubic feet per day
BP	BP America Production Co., a wholly-owned subsidiary of BP plc.
BTU	A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM	CDM Resouce Management, Ltd.
CDM GP	CDM OLP GP, LLC, the sole general partner of CDM
CDM LP	CDMR Holdings, LLC, the sole limited partner of CDM
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
DOT	U.S. Department of Transportation
EIA	Energy Information Administration
Enbridge	Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Interstate), LP and Enbridge Pipleines (Texas Gathering), LP
EnergyOne	FrontStreet EnergyOne LLC
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FrontStreet	FrontStreet Hugoton LLC
Fund V	Hicks, Muse, Tate & Furst Equity Fund V, L.P.
GAAP	Accounting principles generally accepted in the United States
GE	General Electric Company
GE EFS	General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer LP
GECC	General Electric Capital Corporation, an indirect wholly owned subsidiary of GE
General Partner	Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of the General Partner, which effectively manages the business and affairs of the Partnership
GSTC	Gulf States Transmission Corporation
HLPSA	Hazardous Liquid Pipeline Safety Act
HM Capital	HM Capital Partners LLC
HM Capital Investors	Regency Acquisition LP, HMTF Regency L.P., HM Capital and funds managed by HM Capital, including Fund V, and certain co-investors, including some of the directors and officers of the Managing GP
HMTF Gas Partners	HMTF Gas Partners II, LP
HMTF Regency	HMTF Regency L.P.
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
MMbtu	One million BTUs
Mmbtu/d	One million BTUs per day
MMcf	One million cubic feet
MMcf/d	One million cubic feet per day
MQD	Minimum Quarterly Distribution
NGA	Natural Gas Act of 1938
NGLs	Natural gas liquids
NGPA	Natural Gas Policy Act of 1978
NGPSA	Natural Gas Pipeline Safety Act of 1968, as amended
NPDES	National Pollutant Discharge Elimination System
NASDAQ	Nasdaq Stock Market, LLC
NYMEX	New York Mercantile Exchange
OSHA	Occupational Safety and Health Act
Partnership	Regency Energy Partners LP
Pueblo	Pueblo Midstream Gas Corporation
RCRA	Resource Conservation and Recovery Act
RGS	Regency Gas Services LLC
RIGS	Regency Intrastate Gas LLC
SEC	Securities and Exchange Commission
Tcf	One trillion cubic feet
Tcf/d	One trillion cubic feet per day
TexStar	TexStar Field Services, L.P. and its general partner, TexStar GP, LLC
TRRC	Texas Railroad Commission

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	REGENCY ENERGY PARTNERS LP
	By:	/s/ Stephen L. Arata
		Stephen L. Arata
		Executive Vice President and Chief Financial Officer
Date: May 9, 2008

EX-99.1

Exhibit 99.1.  Selected Financial Data

The historical financial information presented below for the Partnership and our predecessors, Regency LLC Predecessor and Regency Gas Services LP (formerly Regency Gas Services LLC), was derived from our audited consolidated financial statements as of December 31, 2007, 2006, 2005, and 2004 and for the years ended December 31, 2007, 2006, and 2005, the one-month period ended December 31, 2004, the eleven-month period ended November 30, 2004, and the period from inception (April 2, 2003) to December 31, 2003.  See “Item 7 — Management’s Discussions and Analysis of Financial Condition and Results of Operations — History of the Partnership and its Predecessor” for a discussion of why our results may not be comparable, either from period to period or going forward.

We refer to Regency Gas Services LLC as “Regency LLC Predecessor” for periods prior to its acquisition by the HM Capital investors.

	Regency Energy Partners LP												Regency LLC Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005			Period from Acquisition (December 1, 2004) to December 31, 2004			Period from January 1, 2004 to November 30, 2004			Period from inception (April 2, 2003) to December 31, 2004
	(in thousands except per unit data)
Statement of Operations Data:
Total revenue	$	1,190,238		$	896,865		$	709,401		$	47,857		$	432,321		$	186,533
Total operating expense		1,130,874			857,005			695,366			45,112			404,251			178,172
Operating income		59,364			39,860			14,035			2,745			28,070			8,361
Other income and deductions
Interest expense, net		(52,016	)		(37,182	)		(17,880	)		(1,335	)		(5,097	)		(2,392	)
Loss on debt refinancing		(21,200	)		(10,761	)		(8,480	)		-			(3,022	)		-
Other income and deductions, net		1,252			839			733			64			186			205
Net income (loss) from continuing operations		(12,600	)		(7,244	)		(11,592	)		1,474			20,137			6,174
Discontinued operations		-			-			732			-			(121	)		-
Income tax expense		931			-			-			-			-			-
Minority interest in net income from subsidiary		305			-			-			-			-			-
Net income (loss)	$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016		$	6,174
Less:
Net income through January 31, 2006		-			1,564
Net loss for partners	$	(13,836	)	$	(8,808	)
General partner interest		(393	)		(176	)
Benefical conversion feature for Class C common units		1,385			3,587
Limited partner interest	$	(14,828	)	$	(12,219	)
Basic and diluted net loss per common and subordinated unit (1)	$	(0.40	)	$	(0.30	)
Cash distributions per common and subordinated unit		1.52			0.9417
Basic and diluted net loss per Class B common unit (1)		-			(0.17	)
Cash distributions per Class B common unit		-			-
Income per Class C common unit due to beneficial conversion feature (1)		0.48			1.26
Cash distributions per Class C common unit		-			-
Basic and diluted net income per Class E common unit		1.23			-
Cash distributions per Class E common unit		2.06			-
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	913,109		$	734,034		$	609,157		$	328,784					$	118,986
Total assets		1,278,410			1,013,085			806,740			492,170						164,330
Long-term debt (long-term portion only)		481,500			664,700			428,250			248,000						55,387
Net equity		563,293			212,657			230,962			181,936						59,856
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	79,529		$	44,156		$	37,340		$	(4,311	)	$	32,401		$	6,494
Investing activities		(157,933	)		(223,650	)		(279,963	)		(130,478	)		(84,721	)		(123,165	)
Financing activities		99,443			184,947			242,949			132,515			56,380			118,245
Other Financial Data:
Total segment margin	$	214,093		$	156,419		$	76,536		$	6,870		$	69,559		$	23,072
EBITDA		94,185			69,592			30,191			4,470			35,242			12,890
Maintenance capital expenditures		8,764			16,433			9,158			358			5,548			1,633
Segment Financial and Operating Data:
Gathering and Processing Segment:
Financial data
Segment margin	$	154,761		$	111,372		$	60,864		$	6,262		$	61,347		$	18,805
Operating expenses		53,496			35,008			22,362			1,655			16,230			6,131
Operating data
Natural gas throughput (MMbtu/d)		772,930			529,467			345,398			314,812			303,345			211,474
NGL gross production (Bbls/d)		21,808			18,587			14,883			16,321			14,487			9,434
Transportation segment
Financial data
Segment margin	$	59,332		$	45,047		$	15,672		$	608		$	8,212		$	4,267
Operating expenses		4,504			4,488			1,929			164			1,556			881
Operating data
Throughput (MMbtu/d)		751,761			587,098			258,194			161,584			192,236			211,569

(1) The year ended December 31, 2006 amounts have been corrected for an error made in the calculation of loss per unit resulting from the issuance of Class C common units at a discount.

(2) See "- Non-GAAP Financial Measures" for a reconciliation to its most directly comparable GAAP measure.

Non-GAAP Financial Measures

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

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

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

·   The ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash available for distribution to our unit holders and General Partner;

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

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

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

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

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

	Regency Energy Partners LP												Regency LLC Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006				Year Ended December 31, 2005		Period from Acquisition (December 1, 2004) to December 31, 2004				Period from January 1, 2004 to November 30, 2004		Period from inception (April 2, 2003) to December 31, 2003
	(in thousands except per unit data)
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	$	79,529		$	44,156		$	37,340		$	(4,311	)	$	32,401		$	6,494
Add (deduct):
Depreciation and amortization		(57,069	)		(39,287	)		(24,286	)		(1,793	)		(10,461	)		(4,658	)
Write-off of debt issuance costs		(5,078	)		(10,761	)		(8,480	)		-			(3,022	)		-
Equity income		43			532			312			56			-			-
Risk management portfolio value changes		(14,667	)		2,262			(11,191	)		322			-			-
Loss (gain) on assets sales		(1,522	)		-			1,254			-			-			-
Unit based compensation expenses		(15,534	)		(2,906	)		-			-			-			-
Accrued revenues and accounts receivable		28,789			5,506			43,012			(2,568	)		19,832			31,966
Other current assets		1,394			(104	)		2,644			2,456			1,169			1,070
Accounts payable, accrued cost of gas and liquids and accrued liabilities		(30,089	)		1,359			(52,651	)		(548	)		(18,122	)		(26,880	)
Accrued taxes payable		(835	)		(492	)		(806	)		921			(1,475	)		(906	)
Other current liabilities		984			(3,148	)		(1,269	)		242			(502	)		(917	)
Minority interest		(305	)		-			-			-			-			-
Proceeds from early termination of interest rate swap		-			(4,940	)		-			-			-			-
Amount of swap termination proceeds reclassified into earnings		1,078			3,862			-			-			-			-
Other assets and liabilities		(554	)		(3,283	)		3,261			6,697			196			5
Net (loss) income	$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016		$	6,174
Add:
Interest expense, net		52,016			37,182			17,880			1,335			5,097			2,392
Depreciation and amortization		55,074			39,654			23,171			1,661			10,129			4,324
Income tax expense		931			-			-			-			-			-
EBITDA	$	94,185		$	69,592		$	30,191		$	4,470		$	35,242		$	12,890
Reconciliation of "total segment margin" to net (loss) income
Net (loss) income	$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016		$	6,174
Add (deduct):
Operation and maintenance		58,000			39,496			24,291			1,819			17,786			7,012
General and administrative		39,713			22,826			15,039			645			6,571			2,651
Loss on assets sales		1,522			-			-			-			-			-
Management services termination fee		-			12,542			-			-			-			-
Transaction expenses		420			2,041			-			-			7,003			724
Depreciation and amortization		55,074			39,654			23,171			1,661			10,129			4,324
Interest expense, net		52,016			37,182			17,880			1,335			5,097			2,392
Loss on debt refinancing		21,200			10,761			8,480			-			3,022			-
Other income and deductions, net		(1,252	)		(839	)		(733	)		(64	)		(186	)		(205	)
Discontinued operations		-			-			(732	)		-			121			-
Income tax expense		931			-			-			-			-			-
Minority interest in net income from subsidairy		305			-			-			-			-			-
Total segment margin	$	214,093		$	156,419		$	76,536		$	6,870		$	69,559		$	23,072

EX-99.2

Exhibit 99.2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

OVERVIEW.We are a growth-oriented publicly-traded Delaware limited partnership engaged in the gathering, processing, contract compression, marketing and transportation of natural gas and NGLs.  We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas, Oklahoma, and Colorado.

OUR OPERATIONS. Prior to the acquisition of CDM in January 2008, we managed our business and analyzed and reported our results of operations through two business segments.

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

·   Transportation: we deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Interstate Pipeline system.

On January 15, 2008, we acquired CDM, which now comprises our contract compression segment.  Our contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow.  Our integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs.  We are responsible for the installation and ongoing operation, service, and repair of our compression units, which we modify as necessary to adapt to our customers’ changing operating conditions.

Through December 31, 2007, all of our revenue is derived from, and all of our assets and operations are part of our gathering and processing segment and our transportation segment.  As such the following discussion of our financial condition and results of operation does not reflect our contract compression segment.

Gathering and processing segment.Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas that we gather and process, our current contract portfolio, and natural gas and NGL prices.  We measure the performance of this segment primarily by the segment margin it generates.  We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements.  Under fee-based arrangements, we earn fixed cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs.  We regard the segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements.  The following is a summary of our most common contractual arrangements:

·    Fee Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering 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.  These arrangements provide stable cash flows, but minimal, if any, upside in high commodity price environments. The FrontStreet acquisition increases the size of our fee based operation and provides us with steady cash flow.

Exhibit 99.2 - 1

·  Percent of Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at price based on published indeed prices.  In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and retained sale 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 can’t be negative.  We regard the margin from this type of arrangement as an important analytical measure of these arrangements.  The price paid to produce is based pm an agreed percentage of one of the following:(1) the actual 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 correlated directly with the prices of natural gas and NGLs (although there is often a fee-based component to the contract in addition to the commodity sensitive components).

·  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 processing in unfavorable price environments.

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

Another way we minimize our exposure to commodity price fluctuations is by executing swap contracts settled against ethane, propane, butane, natural gasoline, crude oil, and natural gas market prices.  We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

Transportation Segment.  Results of operations from our Transportation segment are determined primarily by the volumes of natural gas transported on our Regency Intrastate Pipeline system and the level of fees charged to our customers or the margins received from purchases and sales of natural gas.  We generate revenues and segment margins for our Transportation segment principally under fee-based transportation contracts or through the purchase of natural gas at one of the inlets to the pipeline and the sale of natural gas at an outlet.  The margin we earn from our transportation activities is directly related to the volume of natural gas that flows through our system and is not directly dependent on commodity prices.  If a sustained decline in commodity prices should result in a decline in volumes, our revenues from these arrangements would be reduced.

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

·   Firm Transportation.  When we agree to provide firm transportation service, we become 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.

Exhibit 99.2 - 2

·   Interruptible Transportation.  When we agree to provide interruptible transportation service, we become obligated to transport natural gas nominated by the shipper only to the extent that we have available capacity.  For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped.

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

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

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

HOW WE EVALUATE OUR OPERATIONS.Our management uses a variety of financial and operational measurements to analyze our performance.  We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis.  These measures include volumes, segment margin and operating and maintenance expenses on a segment basis and EBITDA on a company-wide basis.

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

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

Segment Margin. We calculate our Gathering and processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.  Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing of natural gas.

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

Exhibit 99.2 - 3

Total Segment Margin. Segment margin from Gathering and Processing, together with segment margin from Transportation, comprise total segment margin.  We use total segment margin as a measure of performance.  See “Selected Financial Data — Non-GAAP Financial Measures” for a reconciliation of this non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measures, net cash flows provided by (used in) operating activities and net income (loss).

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

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

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

·   the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unit holders 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 or capital structure; and

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

EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded master limited partnership.  See “Exhibit 99.1- Financial Data-Non GAAP Financial Measure” for a reconciliation of EBITDA to net cash flows provided by (used in) operating activities and to net income (loss).

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

Natural Gas Supply, Demand and Outlook. Natural gas remains a critical component of energy consumption in the United States.  The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.  We believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production.  Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized.  We believe that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market.  We believe that an increase in United States natural gas production and additional sources of supply such as liquefied natural gas and other imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

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

Exhibit 99.2 - 4

Effect of Interest Rates and Inflation. Interest rates on existing and future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.  Although increased financing costs could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

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

HISTORY OF THE PARTNERSHIP AND ITS PREDECESSOR

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

Acquisition of El Paso and Duke Energy Field Services Assets.  In June 2003, Regency Gas Services LLC acquired certain natural gas gathering, processing, and transportation assets located in north Louisiana and the mid-continent region of the United States from subsidiaries of El Paso Corporation for $119,541,000.  In March 2004, Regency Gas Services LLC acquired certain natural gas gathering and processing assets located in west Texas from Duke Energy Field Services, LP for $67,264,000, including transactional costs.  Prior to our acquisitions, these assets were operated as components of the seller’s much larger midstream operations.  There were no material financial results for periods prior to June 2003.

The HM Capital Investors’ Acquisition of Regency Gas Services LLC.  On December 1, 2004, the HM Capital Investors acquired all of the outstanding equity interests in our predecessor, Regency Gas Services LLC, from its previous owners.  The HM Capital Investors accounted for this acquisition as a purchase, and purchase accounting adjustments, including goodwill and other intangible assets, have been “pushed down” and are reflected in the financial statements of Regency Gas Services LLC for the period subsequent to December 1, 2004.  This push down accounting increased deprecation, amortization and interest expenses for periods subsequent to December 1, 2004.  We refer to this transaction as the HM Capital Transaction.  For periods prior to the HM Capital Transaction, we designated such periods as Regency LLC Predecessor.

Initial Public Offering.  Prior to the closing of our initial public offering on February 3, 2006, Regency Gas Services LLC was converted into a limited partnership named Regency Gas Services LP, and was contributed to us by Regency Acquisition LP, a limited partnership indirectly owned by the HM Capital Investors.

Enbridge Asset Acquisition.TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in east and south Texas from subsidiaries of Enbridge for $108,282,000 inclusive of transaction expenses on December 7, 2005.  The Enbridge acquisition was accounted for using the purchase method of accounting.  The results of operations of the Enbridge assets are included in our statements of operations beginning December 1, 2005.

Acquisition of TexStar.On August 15, 2006, we acquired all the outstanding equity of TexStar for $348,909,000, which consisted of $62,074,000 in cash, the issuance of 5,173,189 Class B common units valued at $119,183,000 to an affiliate of HM Capital, and the assumption of $167,652,000 of TexStar’s outstanding bank debt.  Because the TexStar acquisition was a transaction between commonly controlled entities, we accounted for the TexStar acquisition in a manner similar to a pooling of interests.  As a result, our historical financial statements and the historical financial statements of TexStar have been combined to reflect the historical operations, financial position and cash flows for periods in which common control existed, December 1, 2004 forward.

Exhibit 99.2 - 5

Pueblo Acquisition.On April 2, 2007, we acquired a 75 MMcf/d gas processing and treating facility, 33 miles of gathering pipelines and approximately 6,000 horsepower of compression.  The purchase price for the Pueblo acquisition consisted of (1) the issuance of 751,597 common units, valued at $19,724,000 and (2) the payment of $34,855,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $108,000.  The Pueblo acquisition was accounted for using the purchase method of accounting.  The results of operations of the Pueblo assets are included in our statements of operations beginning April 1, 2007.

GE EFS acquisition of HM Capital’s Interest.  On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of GECC, acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners.  Concurrently, Regency LP Acquirer LP, another indirect subsidiary of GECC, acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management team.  As a part of this acquisition, affiliates of HM Capital Partners entered into an agreement to hold 4,692,417 of the Partnership’s common units for a period of 180 days.  In addition, a separate affiliate of HM Capital Partners entered into an agreement to hold 3,406,099 of the Partnership’s common units for a period of one year.

GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of GE.  For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.”  Concurrent with the Partnership's issuance of common units in July and August 2007, GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $7,735,000 to maintain the General Partner’s two percent interest in the Partnership.

Concurrent with the GE EFS acquisition, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units to for a total consideration of $24.00 per unit.  Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

The Partnership was not required to record any adjustments to reflect GE EFS’s acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).

Acquisition of FrontStreet Hugoton, LLC.On January 7, 2008 we acquired FrontStreet Hugoton, LLC from ASC and EnergyOne (the “Sellers”) for a total consideration of (1) the issuance of 4,701,034 Class E common units of the Partnership to ASC and (2) the payment of $11,752,000 in cash to EnergyOne.  Because the FrontStreet acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), we accounted for the acquisition in a manner similar to the pooling of interest method of accounting.  Under this method of accounting, the FrontStreet acquisition will reflect historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities.  Further, as a result of this method of accounting, certain transaction costs that would normally be capitalized will be expensed.  The Partnership recast its financial statements to include the operations of FrontStreet from June 18, 2007 (the date upon which common control began) forward.

Exhibit 99.2 - 6

RESULTS OF OPERATIONS

Year Ended December 31, 2007 vs. Year Ended December 31, 2006

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

	Year Ended December 31,
	2007			2006			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	1,190,238		$	896,865		$	293,373			33	%
Cost of gas and liquids		976,145			740,446			235,699			32
Total segment margin (1)		214,093			156,419			57,674			37
Operation and maintenance		58,000			39,496			18,504			47
General and administrative (2)		39,713			22,826			16,887			74
Loss on asset sales, net		1,522			-			1,522			n/m
Management services termination fee		-			12,542			(12,542	)		(100	)
Transaction expenses		420			2,041			(1,621	)		(79	)
Depreciation and amortization		55,074			39,654			15,420			39
Operating income		59,364			39,860			19,504			49
Interest expense, net		(52,016	)		(37,182	)		(14,834	)		40
Loss on debt refinancing		(21,200	)		(10,761	)		(10,439	)		97
Other income and deductions, net		1,252			839			413			49
Loss before income taxes and minority interest		(12,600	)		(7,244	)		(5,356	)		74
Income tax expense		931			-			931			n/m
Minority interest in net income from subsidairy		305			-			305			n/m
Net loss	$	(13,836	)	$	(7,244	)	$	(6,592	)		91	%
System inlet volumes (MMBtu/d) (3)		1,225,918			1,010,642			215,276			21	%

(1) For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - - Selected Financial Data-Non -GAAP Measures".

(2) Includes a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common units options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS.

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

n/m = not meaningful

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

	Year Ended December 31,
	2007		2006		Change		Percent
	(in thousands except percentages and volume data)
Gathering and Processing Segment
Financial data:
Segment margin (1)	$	154,761	$	111,372	$	43,389		39	%
Operation and maintenance		53,496		35,008		18,488		53
Operating data:
Throughput (MMBtu/d)		772,930		529,467		243,463		46
NGL gross production (Bbls/d)		21,808		18,587		3,221		17
Transportation Segment
Financial data:
Segment margin (1)	$	59,332	$	45,047	$	14,285		32	%
Operation and maintenance		4,504		4,488		16		0
Operating data:
Throughput (MMBtu/d)		751,761		587,098		164,663		28

(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - Selected Financial Data- Non-GAAP Financial Measures".

Exhibit 99.2 - 7

Net Loss.Net loss for the year ended December 31, 2007 increased $6,592,000 compared with the year ended December 31, 2006.  An increase in total segment margin of $57,674,000, primarily due to organic growth in the gathering and processing segment; the absence in 2007 of management services termination fees of $12,542,000 from our initial public offering and TexStar acquisition; and a decrease in transaction expenses of $1,621,000 associated with acquisitions of entities under common control were more than offset by:

·   an increase in general and administrative expense of $16,887,000 primarily due to a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS and higher employee related expenses;

·   an increase in interest expense, net of $14,834,000 primarily due to increased levels of borrowings used primarily to finance our Pueblo acquisition and growth capital projects;

·   an increase in loss on debt refinancing of $10,439,000 primarily due to a $16,122,000 early termination penalty in 2007 associated with the redemption of 35 percent of our senior notes partially offset by a $5,683,000 decrease in the write-off of capitalized debt issuance costs related to paying off or refinancing credit facilities;

·   $5,792,000 net income attributable to our FrontStreet assets;

·   an increase in depreciation and amortization of $15,420,000 primarily due to higher levels of depreciation from projects completed since December 31, 2006 and our Pueblo acquisition; and

·   a net loss on the sale of certain non-core assets of $1,522,000 in the year ended December 31, 2007.

Segment Margin.  Total segment margin for the year ended December 31, 2007 increased $57,674,000 compared with the year ended December 31, 2006.  This increase was attributable to an increase of $43,389,000 in gathering and processing segment margin and an increase of $14,285,000 in transportation segment margin as discussed below.

Gathering and processing segment margin increased to $154,761,000 for the year ended December 31, 2007 from $111,372,000 for the year ended December 31, 2006.  The major components of this increase were as follows:

·   $23,233,000 attributable to organic growth projects in the east and south Texas regions;

·   $22,184,000 attributable to our FrontStreet assets;

·   $15,538,000 attributable to organic growth in the north Louisiana region; and offset by

·   $17,449,000 of non-cash losses from certain risk management activities.

Transportation segment margin increased to $59,332,000 for the year ended December 31, 2007 from $45,047,000 for the year ended December 31, 2006.  The major components of this increase were as follows:

·   $11,512,000 attributable to increased throughput volumes;

·   $1,752,000 of increased margins related to our merchant function

·   $631,000 attributable to increased margins per unit of throughput; and

·   $390,000 of non-cash gains from certain risk management activities.

Operation and Maintenance. Operations and maintenance expense increased to $58,000,000 in the year ended December 31, 2007 from $39,496,000 for the corresponding period in 2006, a 47 percent increase.  This increase is primarily the result of the following factors:

·   $12,526,000 attributable to our FrontStreet assets;

·   $3,217,000 of increased employee related expenses primarily in the gathering and processing segment resulting from additional employees related to organic growth and employee annual pay raises;

·   $1,219,000 of increased consumable expenses primarily in the gathering and processing segment largely resulting from additional compression;

·   $1,034,000 of increased contractor expense primarily in the gathering and processing segment associated with our Fashing processing plant;

·   $811,000 of increased utility expense primarily in the gathering and processing segment resulting from one of our north Louisiana refrigeration plants placed in service in December 2006; and

·   $637,000 of unplanned outage expense in the transportation segment in 2007 related to the Eastside compressor fire, which represents our estimated thirty day deductible.

Exhibit 99.2 - 8

Partially offsetting these increases in operation and maintenance expense were the following factors:

·   $1,741,000 of insurance proceeds associated with our unplanned compressor outage in the transportation segment in 2007; and

·   $549,000 of decreased rental expense primarily in the gathering and processing segment from fewer leased compressor units.

General and Administrative. General and administrative expense increased to $39,713,000 in the year ended December 31, 2007 from $22,826,000 for the same period in 2006, a 74 percent increase.  The increase is primarily due to:

·   a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS;

·   $3,607,000 of increased employee related expenses resulting from pay raises and the hiring of additional employees;

·   $777,000 of increased professional and consulting expense primarily for Sarbanes-Oxley compliance; and

·   partially offsetting these increases was the absence in 2007 of management fees of $361,000 in 2006.

Other.  In the year ended December 31, 2006, we recorded charges of $12,542,000 for the termination of long-term management services contracts in connection with our initial public offering and TexStar acquisition.  In the years ended December 31, 2007 and 2006, we incurred transaction expenses of $420,000 related to our 2008 FrontStreet acquisition and $2,041,000 related to our TexStar acquisition.  Since these acquisitions involve entities under common control, we accounted for these transactions in a manner similar to pooling of interests and expensed the transaction costs.  In the year ended December 31, 2007, we sold certain non-core assets and recorded a related net charge of $1,522,000.

Depreciation and Amortization.  Depreciation and amortization expense increased to $55,074,000 in the year ended December 31, 2007 from $39,654,000 for the year ended December 31, 2006, a 39 percent increase.  The increase is due to higher depreciation expense of $13,914,000 primarily from projects completed since December 31, 2006, our Pueblo acquisition, and our FrontStreet assets.  Also contributing to the increase was higher identifiable intangible asset amortization of $1,506,000 primarily related to contracts associated with the Pueblo acquisition and the TexStar acquisition in April 2007 and July 2006, respectively.

Interest Expense, Net. Interest expense, net increased $14,834,000, or 40 percent, in the year ended December 31, 2007 compared to the same period in 2006.  Of this increase, $8,243,000 was attributable to increased levels of borrowings and $4,026,000, was attributable to higher interest rates partially offset by the 2006 reclassification of $2,607,000 from accumulated other comprehensive income associated with the gain upon the termination of an interest rate swap.

Loss on Debt Refinancing.  In the year ended December 31, 2007, we paid a $16,122,000 early repayment penalty associated with the redemption of 35 percent of our senior notes.  We also expensed $5,078,000 of debt issuance costs related to the pay off of the term loan facility and the early termination of senior notes.  In the year ended December 31, 2006, we wrote-off $5,626,000 of debt issuance costs to amend and restate our credit facility and we wrote-off $5,135,000 of debt issuance costs associated with paying off TexStar’s loan agreement as part of our TexStar acquisition.

Exhibit 99.2 - 9

Year Ended December 31, 2006 vs. Year Ended December 31, 2005

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

	Year Ended December 31,
	2006			2005			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	896,865		$	709,401		$	187,464			26	%
Cost of gas and liquids		740,446			632,865			107,581			17
Total segment margin (1)		156,419			76,536			79,883			104
Operation and maintenance		39,496			24,291			15,205			63
General and administrative		22,826			15,039			7,787			52
Management services termination fee		12,542			-			12,542			n/m
Transaction expenses		2,041			-			2,041			n/m
Depreciation and amortization		39,654			23,171			16,483			71
Operating income		39,860			14,035			25,825			184
Interest expense, net		(37,182	)		(17,880	)		(19,302	)		(108	)
Loss on debt refinancing		(10,761	)		(8,480	)		(2,281	)		27
Other income and deductions, net		839			733			106			14
Loss from continuing operations		(7,244	)		(11,592	)		4,348			38
Discontinued operations		-			732			(732	)		(100	)
Net loss	$	(7,244	)	$	(10,860	)	$	3,616			33	%
System inlet volumes (MMBtu/d)(2)		1,010,642			603,592			407,050			67	%

(1) For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - - Selected Financial Data-Non -GAAP Measures".

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

n/m = not meaningful

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

	Year Ended December 31,
	2006		2005		Change		Percent
	(in thousands except percentages and volume data)
Gathering and Processing Segment
Financial data:
Segment margin (1)	$	111,372	$	60,864	$	50,508		83	%
Operation and maintenance		35,008		22,362		12,646		57
Operating data:
Throughput (MMBtu/d)		529,467		345,398		184,069		53
NGL gross production (Bbls/d)		18,587		14,883		3,704		25
Transportation Segment
Financial data:
Segment margin (1)	$	45,047	$	15,672	$	29,375		187	%
Operation and maintenance		4,488		1,929		2,559		133
Operating data:
Throughput (MMBtu/d)		587,098		258,194		328,904		127

(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - Selected Financial Data- Non-GAAP Financial Measures".

Net loss. Net loss for the year ended December 31, 2006 decreased $3,616,000 compared with the year ended December 31, 2005.  The decrease in net loss was primarily attributable to an increase in total segment margin of $79,883,000 largely due to increased contributions from the Transportation segment resulting from the completion on our Regency Intrastate Enhancement Project in December 2005, a full year of segment margin from our TexStar acquisition and increased performance from the remainder of the Gathering and Processing segment.  The increase in total segment margin was offset by increases in the following expenses:

Exhibit 99.2 - 10

·   interest expense, net increased $19,302,000 primarily due to increased levels of borrowing to fund acquisitions and capital expenditures;

·   depreciation and amortization expense increased $16,483,000 primarily due to a full year of expense in 2006 versus a partial year’s expense in 2005 due to the timing of acquisitions and completion of capital projects;

·   operation and maintenance increased $15,205,000 primarily due to a full year of expense in 2006 for the TexStar

·   management service termination fees of $12,542,000 in 2006, which were not present in 2005;

·   general and administrative expenses increased $7,787,000 primarily resulting from TexStar general and administrative expenses, the accrual of non-cash expense associated with our LTIP and higher employee-related expenses associated with the hiring of key personnel to assist in achieving our strategic objectives;

·   loss on debt refinancing increased $2,281,000 resulting from increased write-offs of capitalized debt issuance costs related to certain credit facilities that we refinanced in 2006; and

·   transaction expenses of $2,041,000 recorded in 2006 related to the TexStar acquisition.

Segment Margin. Total segment margin for the year ended December 31, 2006 increased to $156,419,000 from $76,536,000 for the year ended December 31, 2005, representing a 104 percent increase.

Gathering and Processing segment margin for the year ended December 31, 2006 increased to $111,372,000 from $60,864,000 for the year ended December 31, 2005, representing an 83 percent increase.  The major elements driving this increase in segment margin are as follows:

·   $23,513,000 attributable to the operations of the other TexStar assets for a full year in 2006 versus one month of operations in 2005;

·   $13,986,000 in non-cash losses due to changes to the value of risk management assets for which we applied to mark-to-market accounting in the first six months of 2005 prior to our election of hedge accounting;

·   $6,347,000 contributed by the Elm Grove and Dubberly refrigeration plants beginning in May 2006 (Elm Grove) and December 2006 (Dubberly);

·   $4,553,000 contributed by the Como assets that were acquired on July 25, 2006;and

·   $2,109,000 of other changes.

Transportation segment margin for the year ended December 31, 2006 increased to $45,047,000 from $15,672,000 for the year ended December 31, 2005, a 187 percent increase.  This increase was attributable to the expansion and extension of the line completed in late 2005, as well as additional improvements in 2006.  The major drivers of this growth are as follows:

·   $15,931,000 attributable to increased volume through-put;

·   $9,443,000 attributable to increased average fees for service; and

·   $4,001,000 of marketing activity generated by our merchant function

Operation and Maintenance. Operation and maintenance expenses for the year ended December 31, 2006 increased to $39,496,000 from $24,291,000 for the year ended December 31, 2005, representing a 63 percent increase.  This increase resulted primarily from $13,248,000 higher expenses associated with TexStar.  Also contributing to the increase from the transportation segment were higher employee-related expenses of $421,000 primarily for overtime associated with maintenance events and increased non-income taxes of $1,665,000, primarily property taxes related to the enhancement of our RIGS pipeline.

General and Administrative. General and administrative expenses for the year ended December 31, 2006 increased to $22,826,000 from $15,039,000 for the corresponding period in 2005.  The increase was attributable in part to higher employee-related expenses of $3,300,000, including higher salary expense associated with hiring key personnel to assist in achieving our strategic objectives.  Also contributing to the increase was the accrual of non-cash expense of $2,906,000 associated with our long-term incentive plan.  TexStar contributed $1,519,000 to the increase in general and administrative expense.

Exhibit 99.2 - 11

Management Services Termination Fee. In the three months ended March 31, 2006 we recorded a one-time charge of $9,000,000 for the termination of two long-term management services contracts in connection with our initial public offering, paid with proceeds from the initial public offering.  In the three months ended September 30, 2006 we recorded a one-time charge of $3,542,000 for the termination of a management services contract associated with our TexStar acquisition.

Transaction Expenses. We incurred transaction expenses of $2,041,000 in 2006 related to our TexStar acquisition.  Since our TexStar acquisition involved entities under common control, we accounted for the transaction in a manner similar to a pooling of interests and we expensed the transaction costs.

Depreciation and Amortization. Depreciation and amortization expense for the year ended December 31, 2006 increased to $39,654,000 from $23,171,000 for the year ended December 31, 2005, representing a 71 percent increase.  Depreciation and amortization expense increased $7,261,000 primarily due to the higher depreciable basis in the transportation segment resulting from the completion of our Regency Intrastate Enhancement Project in December 2005.  The new depreciable basis of assets from our TexStar acquisition in the Gathering and Processing segment contributed $6,898,000 to the increase.  Depreciation and amortization expense in the remainder of the Gathering and Processing segment increased $1,977,000 due primarily to the completion of various capital projects.

Interest Expense, Net. Interest expense, net for the year ended December 31, 2006 increased to $37,182,000 from $17,880,000 for the prior year period.  Of the $19,302,000 increase, $19,226,000 was attributable to increased borrowings, $3,166,000 was attributable to increased interest rates, and $771,000 was attributable to reduced unrealized gains on mark-to-market accounting for interest rate swaps, offset by $3,862,000 of proceeds from the early termination of three interest rate swap contracts reclassified into earnings from accumulated other comprehensive income.

Loss on Debt Refinancing. For the year ended December 31, 2006 we expensed $10,761,000 of debt issuance costs to amend and restate our credit facility, of which $5,135,000 was associated with repaying TexStar’s credit facility as part of our TexStar acquisition.  For the year ended December 31, 2005, as required, we wrote off $8,480,000 of debt issuance costs to amend our credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

·   cash generated from operations;

·   borrowings under our credit facility;

·   debt offerings; and

·   issuance of additional partnership units.

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

See “— History of the Partnership and its Predecessor” for a discussion of why our cash flows and capital expenditures may not be comparable, either from period to period or going forward.

Working Capital Surplus (Deficit). Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due.  During periods of growth capital expenditures, we experience working capital deficits when we fund construction expenditures out of working capital until they are permanently financed.  Our working capital is also influenced by current risk management assets and liabilities due to fair market value changes in our derivative positions being reflected on our balance sheet.  These represent our expectations for the settlement of risk management rights and obligations over the next twelve months, and so must be viewed differently from trade receivables and payables which settle over a much shorter span of time.  Risk management assets and liabilities affect working capital.  When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect these assets and liabilities to affect our ability to pay bills as they come due.

Exhibit 99.2 - 12

Our working capital deficit increased by $3,125,000 from December 31, 2006 to December 31, 2007 primarily due to the following:

·   a $36,331,000 decrease in working capital due to an increase in net current liabilities from risk management activities resulting from an increase in the commodity prices we expect to pay (index prices) on our outstanding swaps as compared to the commodity prices we expect to receive upon settlement;

·   a $23,832,000 increase in working capital resulting from an increase in cash and cash equivalents primarily due to the timing of payment of accounts payable; and

·   a $8,976,000 increase in working capital resulting from an increase in net accounts receivable and payable due to the timing of cash receipts and payments.

Cash Flows from Operating Activities.  Net cash flows provided by operating activities increased $35,373,000, or 80 percent, for the year ended December 31, 2007 as compared to the year ended December 31, 2006.  Cash generated from operations increased primarily due to increased total segment margin of $57,674,000, primarily due to organic growth in the gathering and processing segment and from operating activity of FrontStreet assets acquired in June 18, 2007.

Net cash flows provided by operating activities increased $6,816,000, or 18 percent, for the year ended December 31, 2006 compared to the corresponding period in 2005.  The primary reason for the increased cash flow was increased margin contributions resulting from the completion of the enhancement of our RIGS pipeline, the installation of additional capacity on our gathering and processing systems and our acquisition of TexStar.  The remaining improvement was attributable to the termination of interest rate swaps in June and December 2006.  We terminated the interest rate swap because in the fourth quarter of 2006 because we refinanced the majority of our variable interest rate debt with fixed rate, 8.375 percent senior notes due in 2013.  These increases in cash flows from operations were partially offset by higher interest costs primarily due to increased borrowings, the payment of management services contract termination fees, the payment of transaction fees related to our TexStar acquisition and losses on the refinancing of credit agreements.

For all periods, we used our cash flows from operating activities together with borrowings under our revolving credit facility for our working capital requirements, which include operation and maintenance expenses, maintenance capital expenditures and repayment of working capital borrowings.  From time to time during each period, the timing of receipts and disbursements required us to borrow under our revolving credit facility.  The maximum amounts of revolving line of credit borrowings outstanding during the years ended December 31, 2007 and 2006 were $178,930,000 and $112,600,000, respectively.

Cash Flows from Investing Activities.  Net cash flows used in investing activities decreased $65,717,000, or 29 percent, in the year ended December 31, 2007 compared to the year ended December 31, 2006.  The decrease is primarily due to our 2006 Como assets acquisition ($81,695,000), proceeds from the asset sales in 2007 of $11,706,000, a decrease in spending on growth and maintenance capital expenditures of $19,121,000, partially offset by our 2007 Pueblo acquisition ($34,855,000).

Growth Capital Expenditures.  In the year ended December 31, 2007, we incurred $84,252,000 of growth capital expenditures.  Growth capital expenditures for the year ended December 31, 2007 primarily relate to the following projects:

·   $8,300,000 for constructing 20 miles of 10 inch diameter pipeline, which will connect the Fashing Processing Plant to our Tilden Processing Plant in south Texas and reconfiguring our Tilden Processing Plant, expected to be completed in the first half of 2008;

·   $11,500,000 to re-build and activate an existing nitrogen rejection unit at our Eustace Processing Plant, completed in the second quarter of 2007;

·   $8,600,000 for constructing 31 miles of 12 inch diameter pipeline in south Texas, completed in the second quarter of 2007;

·   $8,100,000 for the electrification and adding an acid gas injection well at our Tilden Processing Plant, completed in the second quarter of 2007; and

·   $5,947,000 of capital expenditure projects that were carried out by FrontStreet.

Exhibit 99.2 - 13

Our 2008 growth budget includes $208,000,000 of currently identified organic growth capital expenditures, including $118,000,000 for CDM compression for an additional 174,700 horsepower. The significant growth capital expenditures in our gathering and processing segment are for the following projects:

·   $14,300,000, in addition to the $8,300,000 spent in 2007, for constructing 20 miles of 10 inch diameter pipeline, which will connect the Fashing Processing Plant to our Tilden Processing Plant in south Texas and reconfiguring our Tilden Processing Plant, expected to be completed in the first half of 2008;

·   $16,700,000 for constructing a 40 mile, 10 inch diameter pipeline, expected to be completed in 2008;

·   $9,394,000 for construction and equipment related to a joint venture in south Texas;

·   $6,700,000 for compression and gathering in south Texas; and

·   $5,800,000 for Dubach plant expansion.

We expect to fund these growth capital expenditures out of borrowings under our existing credit agreement. We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we distribute our available cash to our unitholders, we depend on borrowings under our credit facility and the proceeds from the issuance and sale of debt and equity securities to finance any future growth capital expenditures or acquisitions.

Maintenance Capital Expenditures.  In the year ended December 31, 2007, we incurred $8,764,000 of maintenance capital expenditures.  Maintenance capital expenditures primarily consist of compressor and plant overhauls, as well as new well connects to our gathering systems, which replace volumes from naturally occurring depletion of wells already connected.  Our 2008 budget for maintenance capital expenditures is $17,000,000.

Net cash flows used in investing activities decreased $56,313,000, or 20 percent, for the year ended December 31, 2006 compared to the year ended December 31, 2005. The decrease was primarily due to lower levels of spending on asset purchases and growth and maintenance capital expenditures, discussed below. We categorize our capital expenditures as either: (a) 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 (b) maintenance capital expenditures, which are made to maintain the existing operating capacity of our assets and to extend their useful lives or to maintain existing system volumes and related cash flows.

Cash Flows from Financing Activities.  Net cash flows provided by financing activities decreased $85,504,000, or 46 percent, in the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily due to the following:

·   a decrease in borrowings under our credit facility of $599,650,000 due to restructuring our capitalization;

·   an increase in partner distributions of $42,789,000 due to increased distributions per unit and an increase in the number of partner units receiving distributions, no partner distributions paid in the quarter ended March 31, 2006 and a partial partner distribution paid in the quarter ended June 30, 2006 resulting from the timing of our initial public offering;

·   an increase in FrontStreet distribution and contributions of $9,695,000 and $13,417,0000, respectively; and

·   an increase in proceeds from equity issuances of $40,846,000 due to the issuance in 2007 of 11,500,000 common units for $353,546,000, net of issuance costs, the proceeds of which were used to repay 35 percent or $192,500,000 of our senior notes, to repay our $50,000,000 term loan, and to pay down our revolving credit facility. In 2006 we issued 13,750,000 common units in our initial public offering and 2,857,143 Class C common units for $312,700,000, net of issuance costs.

Net cash flows provided by financing activities decreased $58,002,000, or 24 percent, for the year ended December 31, 2006 compared to the corresponding period in 2005 primarily due to:

·   42,975,000 net borrowings under our credit facility to finance our TexStar acquisition, organic growth projects, working capital requirements and the costs to amend and restate our credit facility;

·   $37,144,000 of partner distributions made in 2006 not made in 2005; and

·   a decrease in member interest contributions of $68,214,000 as HM Capital Investors infused $72,000,000 into us and TexStar in 2005 for growth capital projects.

Exhibit 99.2 - 14

Capital Resources

Description of Our Indebtedness.As of December 31, 2007, our aggregate outstanding indebtedness totaled $481,500,000 and comprised of $124,000,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes, respectively, as compared to our aggregate outstanding indebtedness as of December 31, 2006, which totaled $664,700,000 and comprised of $114,700,000 in borrowings under our revolving credit facility and $550,000,000 of outstanding senior notes.

Credit Ratings. Moody’s Investors Service has assigned a Corporate Family Rating to us of Ba3, a B1 rating for our senior notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- and a B rating for our senior notes.

Fourth Amended and Restated Credit Agreement. We have a $900,000,000 revolving credit facility. The availability for letters of credit is $100,000,000. We have the option to request an additional $250,000,000 in revolving commitments with 10 business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the fourth amended and restated credit agreement, or the credit facility, have been met.

Obligations under the credit facility are secured by substantially all of our assets and are guaranteed, except for those owned by one of our subsidiaries, by the Partnership and each such subsidiary.  The revolving loans mature in five years. Interest on revolving loans thereunder will be calculated, at the our option, at either: (a) a base rate plus an applicable margin of 0.50 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 1.50 percent per annum. The weighted average interest rate for the revolving and term loan facilities, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs was 8.78 percent for the year ended December 31, 2007. We must pay (i) a commitment fee equal to 0.30 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 1.50 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

The credit facility contains financial covenants requiring us to maintain the ratios of debt to consolidated EBITDA and consolidated EBITDA to interest expense within certain threshold ratios.  The credit facility restricts the ability of RGS to pay dividends and distributions other than reimbursement of the Partnership for expenses and payment of distributions to the Partnership to the extent of our determination of available cash as defined in our partnership agreement (so long as no default or event of default has occurred or is continuing).  The credit facility also contains certain other covenants.

Letters of Credit. At December 31, 2007, we had outstanding letters of credit totaling $27,263,000. The total fees for letters of credit accrue at an annual rate of 1.5 percent, which is applied to the daily amount of letters of credit exposure.

Senior Notes. In 2006, the Partnership and Regency Energy Finance Corp., a wholly owned subsidiary of RGS, issued, in a private placement, $550,000,000 in principal amount of senior notes that mature on December 15, 2013 (“senior notes”).  The senior notes bear interest at 8.375 percent and interest is payable semi-annually in arrears on each June 15 and December 15, and are guaranteed by all of our subsidiaries. In August 2007, we redeemed 35 percent, or $192,500,000, of the aggregate principal amount of the senior notes with the net cash proceeds from our July 2007 equity offering and we paid an early redemption penalty of $16,122,000. In September 2007, the Partnership exchanged its then outstanding 8 3/8 percent senior notes which were not registered under the Securities Act of 1933 for senior notes with identical terms that have been so registered

The senior notes and the guarantees are unsecured and rank equally with all of our and the guarantors’ existing and future unsubordinated obligations.  The senior notes and the guarantees are senior in right of payment to any of our and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees.  The senior notes and the guarantees are effectively subordinated to our and the guarantors’ secured obligations, including our credit facility.

Exhibit 99.2 - 15

The senior notes are guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”), except Finance Corp and FrontStreet.  Information regarding the Partnership’s guarantor and non-guarantors is included in Exhibit 99.4 of this Current Report.  These note guarantees are the joint and several obligations of the Guarantors.  No guarantor may sell or otherwise dispose of all or substantially all of its properties or assets if such sale would cause a default under the terms of the senior notes.  Events of default include nonpayment of principal or interest when due; failure to make a change of control offer; failure to comply with reporting requirements according to SEC rules and regulations; and defaults on the payment of obligations under other mortgages or indentures.

We may redeem the senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100 percent of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change of control, each holder of senior notes will be entitled to require us to purchase all or a portion of its notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the date of purchase.  Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.

The senior notes contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain types of transactions with our affiliates; and (vi) sell assets or consolidate or merge with or into other companies.  If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants. At December 31, 2007, we were in compliance with these covenants.

Equity Offering. In July 2007, the Partnership sold 10,000,000 common units for $32.05 per unit. After deducting underwriting discounts and commissions of $12,820,000, the Partnership received $307,680,000 from this sale, excluding the general partner’s proportionate capital contribution of $6,279,000 and offering expenses to date of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 common units for $32.05 per unit upon exercise by the underwriters of their option to purchase additional units. The Partnership received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000.

The Partnership used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000). With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership redeemed $192,500,000, or 35 percent of its outstanding senior notes, an event which required the Partnership to pay an early redemption penalty of $16,122,000 in August 2007.

Universal Shelf. We have filed with the SEC a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $1,000,000,000 of equity securities, debt securities or a combination thereof. We have remaining $323,747,000 of availability under this shelf registration, subject to customary marketing terms and conditions.

Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations.

Exhibit 99.2 - 16

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2007.

	Payments Due by Period
Contractual Cash Obligations	Total		2008			2009-2010		2011-2012	Thereafter
						(in thousands)
Long-term debt (including interest) (1)	$	693,821	$	38,955	$	77,910	$	189,515	$	387,441
Capital leases		10,093		402		811		870		8,010
Operating leases		1,082		505		390		187		-
Purchase obligations		8,539		8,539		-		-		-
Total (2) (3)	$	713,535	$	48,401	$	79,111	$	190,572	$	395,451

(1) Assumes a constant current LIBOR interest rate of 4.86 percent plus the applicable margin on our revolver.  The principal ($357,500,000) of our outstanding senior notes bears a fixed interest rate of 8 3/8 percent.

(2) 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.

(3) Excludes deferred tax liabilities of $8,642,000 as the amount payable by period cannot be reliably estimated considering the future business plans for the entity that generates the deferred tax liability.

OTHER MATTERS

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on our business, financial condition and results of operations.

Environmental Matters. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations.  As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing and operating our plants, pipelines and other facilities.  Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with environmental laws and regulations.

We have implemented procedures to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require.  We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our business, results of operations and financial condition.

Under an omnibus agreement, Regency Acquisition LP, the entity that formerly owned our General Partner, agreed to indemnify us in an aggregate amount not to exceed $8,600,000, generally for three years after February 3, 2006, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before that date.

FrontStreet has a construction and operation agreement (“C&O Agreement”) with a third party, whereby the third party is required to comply with all applicable environmental standards.  While FrontStreet would be responsible for any environmental contamination as a result of the operation, remedies are provided to FrontStreet under the C&O Agreement allowing it to recover costs incurred to remediate a contaminated site.  Additionally, the C&O Agreement states that FrontStreet is specifically responsible for the removal, remediation, and abatement of Polychlorinated Biphenyls (“Remediation Work”).  However, under the terms of the C&O Agreement, FrontStreet can include up to $2,200,000 of expenditures for Remediation Work related to conditions in existence prior to October 1994.  FrontStreet has obtained an indemnification against any environmental losses for preexisting conditions prior to the acquisition date from the previous owner.  Approximately $750,000 has been escrowed in the event the third party does not agree to include in the cost of service expenditures for Remediation Work.  As of December 31, 2007, FrontStreet has not recorded any obligation for Remediation Work.  The C&O Agreement shall remain in effect until such time as the FrontStreet gathering agreement terminates or the third party is removed as operator in accordance with terms of the C&O Agreement.

Exhibit 99.2 - 17

Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to control contamination of the environment.  These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed.  For example, CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment.  These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment.  Under CERCLA, these persons may be subject to joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur.  It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.  Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition, and certain state law analogs to CERCLA, including the Texas Solid Waste Disposal Act, do not contain a similar exclusion for petroleum.  We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.  We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or comparable state laws.

We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal RCRA, and comparable state statutes.  From time to time, the EPA has considered the adoption of stricter handling, storage, and disposal standards for nonhazardous wastes, including crude oil and natural gas wastes.  We are not currently required to comply with a substantial portion of the RCRA requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent management standards.  It is possible, however, that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste.  Changes in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense.

We currently own or lease sites that have been used over the years by prior owners and by us for natural gas gathering, processing and transportation.  Solid waste disposal practices within the midstream gas industry have improved over the years with the passage and implementation of various environmental laws and regulations.  Nevertheless, some hydrocarbons and wastes have been disposed of or released on or under various sites during the operating history of those facilities that are now owned or leased by us.

Notwithstanding the possibility that these dispositions may have occurred during the ownership of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws.  Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

Assets Acquired from ElPaso. Under the agreement pursuant to which our operating partnership acquired assets from El Paso Field Services LP and its affiliates in 2003, we are indemnified for certain environmental matters.  Those provisions include an indemnity by the El Paso sellers against a variety of environmental claims for a period of five years up to an aggregate of $84,000,000.  The agreement also included an escrow of $9,000,000 relating to claims, including environmental claims. In response to our submission of a claim to the El Paso sellers for a variety of environmental defects at these assets, the El Paso sellers have agreed to maintain $5,400,000 in the escrow account to pay any claims for environmental matters ultimately deemed to be covered by their indemnity.  This amount represents the upper end of the estimated remediation cost calculated by Regency based on the results of its investigations of these assets.

Exhibit 99.2 - 18

Since the time of this agreement, a Final Site Investigation Report has been prepared.  Based on this additional investigation, environmental issues exist with respect to four facilities, including the two subject to accepted claims and two of our processing plants.  The estimated remediation costs associated with the processing plants aggregate $2,750,000.  We believe that any of our obligations to remediate the properties is subject to the indemnity under the El Paso PSA, and we intend to reinstate the claims for indemnification for these plant sites.

In January 2008, the Board of Directors of the General Partner and the Partnership signed a settlement of the El Paso environmental remediation. Under the settlement, El Paso will clean up and obtain “no further action” letters from the relevant state agencies for three owned Partnership facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities at that site. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. The Partnership will release all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced per a specified schedule as El Paso completes its cleanups and the remainder will be released upon completion.

West Texas Assets. A Phase I environmental study was performed on our west Texas assets in connection with our investigation of those assets prior to our purchase of them in 2004.  Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties.  We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. At the time of the negotiation of the agreement to acquire the west Texas assets, management of RGS obtained an insurance policy against specified risks of environmental claims (other than those items known to exist).  The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles.

Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations.  These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions.  We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  In addition, our processing plants, pipelines and compression facilities are becoming subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants.  Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities.  We believe that our operations are in substantial compliance with the federal Clean Air Act and comparable state laws.

Clean Water Act. The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into waters of the United States.  Pursuant to the Clean Water Act and similar state laws, a NPDES, or state permit, or both, must be obtained to discharge pollutants into federal and state waters.  The Clean Water Act and comparable state laws and their respective regulations provide for administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and also provide for penalties and liability for the costs of removing spills from such waters.  In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff.  We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financial condition, or results of operations.

Exhibit 99.2 - 19

Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitat.  While we have no reason to believe that we operate in any area that is currently designated as a habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause us to incur additional costs or to become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety. We are subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of workers.  In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.  We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances.

Safety Regulations. Those pipelines through which we transport mixed NGLs (exclusively to other NGL pipelines) are subject to regulation by the DOT, under the HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.  The HLPSA requires any entity that owns or operates liquids pipelines to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to submit certain reports and provide other information as required by the Secretary of Transportation.  We believe our liquids pipelines are in substantial compliance with applicable HLPSA requirements.

Our interstate, intrastate and certain of our gathering pipelines are also are subject to regulation by the DOT under the NGPSA, which covers natural gas, crude oil, carbon dioxide, NGLs and petroleum products pipelines, and under the Pipeline Safety Improvement Act of 2002, as amended. Pursuant to these authorities, the DOT has established a series of rules which require pipeline operators to develop and implement “integrity management programs” for natural gas pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Similar rules are also in place for operators of hazardous liquid pipelines. The DOT’s integrity management rules establish requirements relating to the design, installation, testing, construction, operation, inspection, replacement and management of pipeline facilities.  We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements.

The states administer federal pipeline safety standards under the NGPSA and have the authority to conduct pipeline inspections, to investigate accidents, and to oversee compliance and enforcement, safety programs, and record maintenance and reporting.  Congress, the DOT and individual states may pass additional pipeline safety requirements, but such requirements, if adopted, would not be expected to affect us disproportionately relative to other companies in our industry.  We believe, based on current information, that any costs that we may incur relating to environmental matters will not adversely affect us.  We cannot be certain, however, that identification of presently unidentified conditions, more vigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

TCEQ Notice of Enforcement. On February 15, 2008, the Texas Commission on Environmental Quality, or TCEQ, sent us a notice of enforcement, or NOE, relating to the air emissions at our Tilden processing plant. The NOE relates to 15 alleged violations occurring during the period from March 2006 through July 2007 of the emissions event reporting and recordkeeping requirements of the TCEQs rules. Specifically, it is alleged that one of our subsidiaries failed to report, using the TCEQ’s electronic data base for emissions events, 15 emissions events within 24 hours of the incident, as required. These events occurred during times of failure of the Tilden plant sulphur recovery unit or ancillary equipment and resulted in the flaring of acid gas.  Of these events, one relates to an alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide and three related to more than 2,500 and less than 40,000 pounds of sulphur dioxide (including two releases of 126 and 393 pounds of hydrogen sulphide). In 2007, the subsidiary completed construction of an acid gas reinjection unit at the Tilden plant and permanently shut down the Sulphur Recovery Unit.

Exhibit 99.2 - 20

All these emission incidents were reported by means of fax or telephone to the TCEQ pursuant to an informal procedure established with the TCEQ by the prior owner of the Tilden plant and, indeed, the subsidiary paid the emission fines in connection with all the incidents. Using that procedure, all except one were timely. The TCEQ has, prior to our subsidiary acquiring the Tilden facility, established its electronic data base for emissions events, but the subsidiary did not report using that electronic facility. It is the failure to report each incident timely using the electronic reporting procedure that is the subject of the NOE. Representatives of the Partnership are scheduled to meet with the staff of the TCEQ in the near future regarding the NOE. Management of the General Partner does not expect the NOE to have a material adverse effect on its results of operations or financial condition.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Revenue and Cost of Sales Recognition. We record revenue and cost of gas and liquids on the gross basis for those transactions where we act as the principal and take title to gas that we purchase for resale.  When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues. We estimate certain revenue and expenses as actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry.  We calculate estimated revenues using actual pricing and measured volumes.  In the subsequent production month, we reverse the accrual and record the actual results.  Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses.  We do not expect actual results to differ materially from our estimates.

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

From the inception of our hedging program in December 2004 through June 30, 2005, we used mark-to-market accounting for our commodity and interest rate swaps.  We recorded realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. Effective July 1, 2005, we elected hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, and determined the then outstanding hedges, excluding crude oil put options, qualified for hedge accounting.  Accordingly, we recorded the unrealized changes in fair value in other comprehensive income (loss) to the extent the hedge are effective.  Effective June 19, 2007, we elected to account for our entire outstanding commodity hedging instruments on a mark-to-market basis except for the portion of commodity hedging instruments where all NGLs products for a particular year were hedged and the hedging relationship was effective. As a result, a portion of our commodity hedging instruments is and will continue to be accounted for using mark-to-market accounting until all NGLs products are hedged for an individual year and the hedging relationship is deemed effective.

Exhibit 99.2 - 21

Purchase Method of Accounting. We make various assumptions in determining the fair values of acquired assets and liabilities.  In order to allocate the purchase price to the business units, we develop fair value models with the assistance of outside consultants.  These fair value models apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions.  An economic value is determined for each business unit.  We then determine the fair value of the fixed assets based on estimates of replacement costs.  Intangible assets acquired consist primarily of licenses, permits and customer contracts.  We make assumptions regarding the period of time it would take to replace these licenses and permits.  We assign value using a lost profits model over that period of time necessary to replace the licenses and permits.  We value the customer contracts using a discounted cash flow model.  We determine liabilities assumed based on their expected future cash outflows.  We record goodwill as the excess of the cost of each business unit over the sum of amounts assigned to the tangible assets and separately recognized intangible assets acquired less liabilities assumed of the business unit.

Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipelines.  We capitalize all construction-related direct labor and material costs, as well as indirect construction costs.  Indirect construction costs include general engineering and the costs of funds used in construction.  Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed asset through the recording of depreciation expense.  We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

We generally compute depreciation using the straight-line method over the estimated useful life of the assets.  Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable.  The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets.  As circumstances warrant, we review depreciation estimates to determine if any changes are needed.  Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Determining whether an impairment has occurred typically requires various estimates and assumptions, including determining which undiscounted cash flows are directly related to the potentially impaired asset, the useful life over which cash flows will occur, their amount, and the asset’s residual value, if any. In turn, measurement of an impairment loss requires a determination of fair value, which is based on the best information available. We derive the required undiscounted cash flow estimates from our historical experience and our internal business plans. To determine fair value, we use our internal cash flow estimates discounted at an appropriate interest rate, quoted market prices when available and independent appraisals, as appropriate.

Equity Based Compensation.  Awards under our LTIP have been made prior to the GE EFS Acquisition generally vested over a three year period on the basis of one-third of the award each year.  Options have a maximum contractual term, expiring ten years after the grant date.  Options granted were valued using the Black-Scholes option pricing model, using assumptions of volatility in the unit price, a ten year term, a strike price equal to the grant-date price per unit, a distribution per unit at the time of grant, a risk-free rate, and an average exercise of the options of four years after vesting is complete.  We have based the assumption that option exercises, on average, will be four years from the vesting date on the average of the mid-points from vesting to expiration of the options. There have been no option awards made subsequent to the GE EFS Acquisition.

RECENT ACCOUNTING PRONOUNCEMENTS

See discussion of new accounting pronouncements in Note 2 in the Notes to the Consolidated Financial Statements included in Exhibit 99.4.

Exhibit 99.2 - 22

EX-99.3

Exhibit 99.3.  Quantitative and Qualitative Disclosure about Market Risk

Risk and Accounting Policies.We are exposed to market risks associated with commodity prices, counterparty credit, and interest rates.  Our management has established comprehensive risk management policies and procedures to monitor and manage these market risks.  Our General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of our General Partner is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Commodity Price Risk. We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs, and other commodities as a result of our gathering, processing and marketing activities, which in the aggregate produce a naturally long position in both natural gas and NGLs.  We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities.  To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial hedges to mitigate the risk.  It is our policy not to take any speculative marketing positions.  In some cases, we may not be able to match pricing terms or to cover our risk to price exposure with financial hedges, and we may be exposed to commodity price risk.

Both our profitability and our cash flow are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty.  Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil.  Adverse effects on our cash flow from reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders.  We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts.

We are a net seller of NGLs and condensate, and as such our financial results are exposed to fluctuations in NGL pricing.  We have executed swap contracts settled against condensate, ethane, propane, butane, and natural gasoline market prices. We have hedged our expected exposure to decline in prices for NGLs and condensate volumes produced for our account in the approximate percentages set forth below:

	2008			2009
NGL		85	%		32	%
Condensate		66			67

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. The following table sets forth certain information regarding our non-trading NGL swaps outstanding at December 31, 2007.  The relevant index price that we pay is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service (OPIS).

Period	Commodity	Notional Volume			We Pay	We Receive			Fair Value Asset/(Liability)
									(in thousands)
January 2008 – December 2008	Ethane		740	(MBbls)	Index	$	0.58-$0.615	($/gallon)	$	(11,155	)
January 2008 – December 2009	Propane		813	(MBbls)	Index	$	0.929-$1.06	($/gallon)		(14,908	)
January 2008 – December 2009	Normal Butane		524	(MBbls)	Index	$	1.119-$1.255	($/gallon)		(10,725	)
January 2008 – December 2009	Natural Gasoline		305	(MBbls)	Index	$	1.409-$1.57	($/gallon)		(5,930	)
January 2008 – December 2009	West Texas Intermediate Crude		475	(MBbls)	Index	$	68.17-$68.38	($/Bbl)		(10,205	)
Total									$	(52,923	)

On March 7, 2008, the Partnership entered into a series of NGL commodity swaps for calendar year 2009 to decrease our expected exposure to NGL prices.  As a result, the Partnership increased the hedged percentage to 75 percent.  A portion of these new NGL commodity swaps were entered into to mitigate the Partnership’s mark-to-market exposure for existing 2009 NGL swaps.  The remaining NGL swaps qualified for hedge accounting.

Credit Risk. Our purchase and resale of natural gas exposes us to credit risk, as the margin on any sale is generally a very small percentage of the total sale price.  Therefore a credit loss can be very large relative to our overall profitability.  We attempt to ensure that we issue credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a parental guarantee.

In January 2005, one of our customers filed for Chapter 11 reorganization under U.S. bankruptcy law.  The customer operates a merchant power plant, for which we provide firm transportation of natural gas.  Under the contract with the customer, the customer is obligated to make fixed payments in the amount of approximately $3,200,000 per year.  The contract, which expires in mid-2012, was originally secured by a $10,000,000 letter of credit.  In December 2005, in connection with other contract negotiations, the letter of credit was reduced to $3,300,000 and we accepted a parent guarantee in the amount of $6,700,000. The customer accepted the firm transportation contract in bankruptcy.  The customer’s plan of reorganization has been confirmed by the bankruptcy court and the customer has since emerged from bankruptcy protection.  At December 31, 2007, the letter of credit is $4,800,000 and customer was current in its payment obligations.

Interest Rate Risk.We are exposed to variable interest rate risk as a result of borrowings under our existing credit facility. As of December 31, 2007, we had $124,000,000 of outstanding long-term balances exposed to variable interest rate risk. An increase of 100 basis points in the LIBOR rate would increase our annual payment by $1,240,000.

On March 5, 2008, we entered into a two year interest rate swaps related to $300,000,000 borrowings under our revolver credit facility, whereby we have effectively locked the base rate for these borrowings at 2.4 percent, plus the applicable margin.

EX-99.4

Exhibit 99.4.  Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Partners

Regency Energy Partners LP:

We have audited the accompanying consolidated balance sheet of Regency Energy Partners LP and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, comprehensive loss, cash flows, and partners’ capital for the year then ended.  These consolidated financial statements are the responsibility of the Partnership’s management.  Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Regency Energy Partners LP and subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for the year ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

May 9, 2008

Exhibit 99.4 - 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Regency GP LLC and Unitholders of Regency Energy Partners LP:

We have audited the accompanying consolidated balance sheet of Regency Energy Partners LP and subsidiaries (the “Partnership”) as of December 31, 2006, and the related consolidated statements of operations, member interest and partners’ capital, comprehensive income (loss) and cash flows for the years ended December 31, 2006 and 2005.  These financial statements are the responsibility of the Partnership's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2006, and the results of the Partnership’s operations and cash flows for the years ended December 31, 2006 and 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, the Partnership accounted for its acquisition of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC as acquisitions of entities under common control in a manner similar to a pooling of interests.

/s/Deloitte & Touche LLP

Dallas, Texas

March 29, 2007 (February 28, 2008 as to Note 4)

Exhibit 99.4 - 2

Regency Energy Partners LP
Consolidated Balance Sheets
(in thousands except unit data)
	December 31,2007			December 31,2006
ASSETS
Current Assets:
Cash and cash equivalents	$	32,971		$	9,139
Restricted cash		6,029			5,782
Accrued revenues and accounts receivable, net of allowance of $61 in 2007 and $181 in 2006		134,109			96,993
Related party receivables		61			755
Assets from risk management activities		-			2,126
Other current assets		6,723			5,279
Total current assets		179,893			120,074
Property, plant and equipment
Gas plants and buildings		134,300			103,490
Gathering and transmission systems		780,761			529,776
Other property, plant and equipment		105,399			73,861
Construction-in-progress		33,552			85,277
Total property, plant and equipment		1,054,012			792,404
Less accumulated depreciation		(140,903	)		(58,370	)
Property, plant and equipment, net		913,109			734,034
Other Assets:
Intangible assets, net of amortization of $8,929 in 2007 and $4,676 in 2006		77,804			76,923
Long-term assets from risk management activities		-			1,674
Other, net of amortization of debt issuance costs of $2,488 in 2007 and $946 in 2006		13,529			17,212
Investments in unconsolidated investee		-			5,616
Goodwill		94,075			57,552
Total other assets		185,408			158,977
TOTAL ASSETS	$	1,278,410		$	1,013,085
LIABILITIES & PARTNERS' CAPITAL
Current Liabilities:
Accounts payable, accrued cost of gas and liquids and accrued liabilities	$	144,930		$	117,254
Related party payables		50			280
Escrow payable		6,029			5,783
Accrued taxes payable		4,274			2,758
Liabilities from risk management activities		37,852			3,647
Other current liabilities		5,123			5,592
Total current liabilities		198,258			135,314
Long-term liabilities from risk management activities		15,073			145
Other long-term liabilities		15,393			269
Long-term debt		481,500			664,700
Minority interest		4,893			-
Commitments and contingencies
Partners' Capital:
Common units (41,283,079 and 21,969,480 units authorized; 40,514,895 and 19,620,396 units issued and outstanding at		490,351			42,192
December 31,2007 and 2006 respectively)
Class B common units (5,173,189 units authorized, issued and outstanding at December 31, 2006)		-			60,671
Class C common units (2,857,143 units authorized, issued and outstanding at December 31, 2006)		-			59,992
Class E common units (4,701,034 units authorized, issued, and outstanding at December 31, 2007)		92,962			-
Subordinated units (19,103,896 units authorized, issued and outstanding at December 31, 2007 and 2006)		7,019			43,240
General partner interest		11,286			5,543
Accumulated other comprehensive income (loss)		(38,325	)		1,019
Total partners' capital		563,293			212,657
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,278,410		$	1,013,085
See accompanying notes to consolidated financial statements

Exhibit 99.4 - 3

Regency Energy Partners LP
Consolidated Statements of Operations
(in thousands except unit data)
	Year Ended December 31,
	2007			2006			2005
REVENUES
Gas sales	$	744,681		$	560,620		$	506,278
NGL sales		347,737			256,672			183,073
Gathering, transportation and other fees, including related party amounts of $1,350, $2,160, and $833		100,644			63,071			27,568
Net realized and unrealized loss from risk management activities		(34,266	)		(7,709	)		(22,243	)
Other		31,442			24,211			14,725
Total revenues		1,190,238			896,865			709,401
OPERATING COSTS AND EXPENSES
Cost of gas and liquids, including related party amounts of $14,165, $1,630, and $523		976,145			740,446			632,865
Operation and maintenance		58,000			39,496			24,291
General and administrative		39,713			22,826			15,039
Loss on asset sales, net		1,522			-			-
Management services termination fee		-			12,542			-
Transaction expenses		420			2,041			-
Depreciation and amortization		55,074			39,654			23,171
Total operating costs and expenses		1,130,874			857,005			695,366
OPERATING INCOME		59,364			39,860			14,035
Interest expense, net		(52,016	)		(37,182	)		(17,880	)
Loss on debt refinancing		(21,200	)		(10,761	)		(8,480	)
Other income and deductions, net		1,252			839			733
LOSS FROM CONTINUING OPERATIONS		(12,600	)		(7,244	)		(11,592	)
DISCONTINUED OPERATIONS
Income from operations of Regency Gas Treating LP  (including gain on disposal of $626)		-			-			732
LOSS BEFORE INCOME TAXES AND MINORITY INTEREST		(12,600	)		(7,244	)		(10,860	)
Income tax expense		931			-			-
Minority interest in net income from subsidairy		305			-			-
NET LOSS	$	(13,836	)	$	(7,244	)	$	(10,860	)
Less: Net income from January 1-31, 2006		-			1,564
Net loss for partners		(13,836	)		(8,808	)
General partner's interest		(393	)		(176	)
Beneficial conversion feature for Class C common units		1,385			3,587
Limited partners' interest	$	(14,828	)	$	(12,219	)
Basic and diluted earnings per unit:
Amount allocated to common and subordinated units	$	(20,620	)	$	(11,333	)
Weighted average number of common and subordinated units outstanding		51,056,769			38,207,792
Loss per common and subordinated unit	$	(0.40	)	$	(0.30	)
Distributions per unit	$	1.52		$	0.9417
Amount allocated to Class B common units	$	-		$	(886	)
Weighted average number of Class B common units outstanding		651,964			5,173,189
Loss per Class B common unit	$	-		$	(0.17	)
Distributions per unit	$	-		$	-
Amount allocated to Class C common units	$	1,385		$	3,587
Total Class C common units outstanding		2,857,143			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	0.48		$	1.26
Distributions per unit	$	-		$	-
Amount allocated to Class E common units	$	5,792
Total Class E common units outstanding		4,701,034
Income per Class E common unit	$	1.23
Distributions per unit	$	2.06
See accompanying notes to consolidated financial statements

Exhibit 99.4 - 4

Regency Energy Partners LP
Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
	Year Ended December 31,
	2007			2006			2005
Net loss	$	(13,836	)	$	(7,244	)	$	(10,860	)
Hedging losses reclassified to earnings		19,362			1,815			5,540
Net change in fair value of cash flow hedges		(58,706	)		10,166			(16,502	)
Comprehensive income (loss)	$	(53,180	)	$	4,737		$	(21,822	)
See accompanying notes to consolidated financial statements

Exhibit 99.4 - 5

Regency Energy Partners LP
Consolidated Statements of Cash Flow
(in thousands)
	Year Ended December 31,
	2007			2006			2005
OPERATING ACTIVITIES
Net loss	$	(13,836	)	$	(7,244	)	$	(10,860	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Depreciation and amortization		57,069			39,287			24,286
Write-off of debt issuance costs		5,078			10,761			8,480
Equity income		(43	)		(532	)		(312	)
Risk management portfolio valuation changes		14,667			(2,262	)		11,191
Loss (gain) on asset sales		1,522			-			(1,254	)
Unit based compensation expenses		15,534			2,906			-
Cash flow changes in current assets and liabilities:		-
Accrued revenues and accounts receivable		(28,789	)		(5,506	)		(43,012	)
Other current assets		(1,394	)		104			(2,644	)
Accounts payable, accrued cost of gas and liquids and accrued liabilities		30,089			(1,359	)		52,651
Accrued taxes payable		835			492			806
Other current liabilities		(984	)		3,148			1,269
Minority interest		305			-			-
Proceeds from early termination of interest rate swap		-			4,940			-
Amount of swap termination proceeds reclassified into earnings		(1,078	)		(3,862	)		-
Other assets and liabilities		554			3,283			(3,261	)
Net cash flows provided by operating activities		79,529			44,156			37,340
INVESTING ACTIVITIES
Capital expenditures		(129,784	)		(142,423	)		(172,567	)
Acquisition of Pueblo		(34,855	)		-			-
Acquisition of Como assets		-			(81,695	)		-
Acquisition of Enbridge assets		-			-			(108,282	)
Acquisition of investment in unconsolidated subsidiary, net of $100 cash		(5,000	)		-			-
Cash outflows for acquisition by HM Capital Investors		-			-			(5,808	)
Proceeds from asset sales		11,706			-			7,099
Other investing changes		-			468			(405	)
Net cash flows used in investing activities		(157,933	)		(223,650	)		(279,963	)
FINANCING ACTIVITIES
Net borrowings under revolving credit facilities		59,300			14,700			50,000
Borrowings under credit facilities		-			599,650			60,000
Repayments under credit facilities		(50,000	)		(858,600	)		(1,650	)
Borrowings under TexStar loan agreement		-			85,000			70,000
Repayments under TexStar loan agreement		-			(155,000	)		-
Proceeds (repayments) of senior notes, net of debt issuance costs		(192,500	)		536,175			-
Partner contributions		7,735			3,786			72,000
Partner distributions		(79,933	)		(37,144	)		-
FrontStreet distributions		(9,695	)		-			-
FrontStreet contributions		13,417			-			-
Debt issuance costs and shelf registration fees		(2,427	)		(10,488	)		(6,201	)
Proceeds from equity issuances, net of issuance costs		353,546			312,700			-
Cash distribution to HM Capital		-			(243,758	)		-
Proceeds from exercise of over allotment option		-			26,163			-
Over allotment option proceeds to HM Capital		-			(26,163	)		-
Acquisition of assets between entities under common control		-			(62,074	)		(1,800	)
Proceeds from promissory note to HMTF Gas Partners		-			-			600
Net cash flows provided by financing activities		99,443			184,947			242,949
Net increase in cash and cash equivalents		21,039			5,453			326
Cash and cash equivalents at beginning of period		9,139			3,686			3,360
Cash acquired from FrontStreet		2,793			-			-
Cash and cash equivalents at end of period	$	32,971		$	9,139		$	3,686
Supplemental cash flow information:
Interest paid and early redemption penalty, net of amounts capitalized	$	67,844		$	33,347		$	16,731
Non-cash capital expenditures in accounts payable		7,761			23,822			21,360
Non-cash capital expenditures for consolidation of investment in previously unconsolidated subsidiary		5,650			-			-
Non-cash capital expenditure upon entering into a capital lease obligation		3,000			-			-
Issuance of common units for acquisition		19,724			-			-
See accompanying notes to consolidated financial statements

Exhibit 99.4 - 6

Regency Energy Partners LP
Consolidated Statements of Partners' Capital
	Units
	Common			Class B			Class C			Class E		Subordinated
Balance - December 1, 2004		-			-			-			-		-
Capital contributions		-			-			-			-		-
Acquisition of fixed assets between entities under common control in excess of historical cost		-			-			-			-		-
Net loss for the year ended December 31, 2005		-			-			-			-		-
Net change in fair value of cash flow hedges		-			-			-			-		-
Net hedging gain reclassified to earnings		-			-			-			-		-
Balance - December 31, 2005		-			-			-			-		-
Net income through January 31, 2006		-			-			-			-		-
Net hedging loss reclassified to earnings		-			-			-			-		-
Net change in fair value of cash flow hedges		-			-			-			-		-
Balance - January 31, 2006		-			-			-			-		-
Contribution of net investment to unitholders		5,353,896			-			-			-		19,103,896
Proceeds from IPO, net of issuance costs		13,750,000			-			-			-		-
Net proceeds from exercise of over allotment option		1,400,000			-			-			-		-
Over allotment option net proceeds to HM Capital Investors		(1,400,000	)		-			-			-		-
Capital reimbursement to HM Capital Partners		-			-			-			-		-
Offering costs		-			-			-			-		-
Issuance of Class B Common Units for TexStar member interest		-			5,173,189			-			-		-
Payment to HM Capital for TexStar net of repayment of promissory note		-			-			-			-		-
Other		-			-			-			-		-
Issuance of Class C Common Units net of costs		-			-			2,857,143			-		-
Issuance of restricted common units		516,500			-			-			-		-
Unit based compensation expenses		-			-			-			-		-
General Partner contributions								-			-		-
Partner distributions		-			-			-			-		-
Net loss from February 1 through December 31,  2006		-			-			-			-		-
Net hedging loss  reclassified to earnings		-			-			-			-		-
Net change in fair value of cash flow hedges		-			-			-			-		-
Balance - December 31, 2006		19,620,396			5,173,189			2,857,143			-		19,103,896
Conversion of Class B and C to common units		8,030,332			(5,173,189	)		(2,857,143	)		-		-
Issuance of common units for acquisition		751,597			-			-			-		-
Issuance of common units		11,500,000			-			-			-		-
Issuance of restricted common units		615,500			-			-			-		-
Forfeitures of restricted common units		(50,333	)		-			-			-		-
Exercise of common unit options		47,403			-			-			-		-
Unit based compensation expenses		-			-			-			-		-
General partner contributions		-			-			-			-		-
Partner distributions		-			-			-			-		-
Acquisition of FrontStreet		-			-			-			4,701,034		-
FrontStreet contributions		-			-			-			-		-
FrontStreet distributions		-			-			-			-		-
Net (loss) income		-			-			-			-		-
Other		-			-			-			-		-
Net hedging activity reclassified to earnings		-			-			-			-		-
Net change in fair value of cash flow hedges		-			-			-			-		-
Balance - December 31, 2007		40,514,895			-			-			4,701,034		19,103,896

See accompanying notes to consolidated financial statements

Exhibit 99.4 - 7

Regency Energy Partners LP
Consolidated Statements of Partners' Capital (continued)
(in thousands except unit data)
	Member Interest			Common Unitholders			Class B Unitholders			Class C Unitholders			Class E Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Total
Balance - December 31, 2004	$	181,936		$	-		$	-		$	-		$	-		$	-		$	-		$	-		$	181,936
Capital contributions		72,000			-			-			-			-			-			-			-			72,000
Acquisition of fixed assets between entities under common control in excess of historical cost		(1,152	)		-			-			-			-			-			-			-			(1,152	)
Net loss for the year ended December 31, 2005		(10,860	)		-			-			-			-			-			-			-			(10,860	)
Net change in fair value of cash flow hedges		-			-			-			-			-			-			-			(16,502	)		(16,502	)
Net hedging gain reclassified to earnings		-			-			-			-			-			-			-			5,540			5,540
Balance - December 31, 2005		241,924			-			-			-			-			-			-			(10,962	)		230,962
Net income through January 31, 2006		1,564			-			-			-			-			-			-			-			1,564
Net hedging loss reclassified to earnings		-			-			-			-			-			-			-			616			616
Net change in fair value of cash flow hedges		-			-			-			-			-			-			-			2,581			2,581
Balance - January 31, 2006		243,488			-			-			-			-			-			-			(7,765	)		235,723
Contribution of net investment to unitholders		(182,320	)		89,337			-			-			-			89,337			3,646			-			-
Proceeds from IPO, net of issuance costs		-			125,907			-			-			-			125,907			5,139			-			256,953
Net proceeds from exercise of over allotment option		-			26,163			-			-			-			-			-			-			26,163
Over allotment option net proceeds to HM Capital Investors		-			(26,163	)		-			-			-			-			-			-			(26,163	)
Capital reimbursement to HM Capital Partners		-			(119,441	)		-			-			-			(119,441	)		(4,876	)		-			(243,758	)
Offering costs		-			(2,056	)		-			-			-			(2,056	)		(83	)		-			(4,195	)
Issuance of Class B Common Units for TexStar member interest		(61,168	)		-			61,168			-			-			-			-			-			-
Payment to HM Capital for TexStar net of repayment of promissory note		-			(30,418	)		-			-			-			(29,744	)		(1,214	)		-			(61,376	)
Other		-			(64	)		(17	)		(9	)					(63	)		(2	)		-			(155	)
Issuance of Class C Common Units net of costs		-			-			-			59,942						-			-			-			59,942
Issuance of restricted common units		-			-			-			-						-			-			-			-
Unit based compensation expenses		-			1,339			146			59						1,304			58			-			2,906
General Partner contributions		-			-			-			-			-			-			3,786			-			3,786
Partner distributions		-			(18,409	)		-			-			-			(18,001	)		(735	)		-			(37,145	)
Net loss from February 1 through December 31,  2006		-			(4,003	)		(626	)		-			-			(4,003	)		(176	)		-			(8,808	)
Net hedging loss  reclassified to earnings		-			-			-			-			-			-			-			7,585			7,585
Net change in fair value of cash flow hedges		-			-			-			-			-			-			-			1,199			1,199
Balance - December 31, 2006		-			42,192			60,671			59,992			-			43,240			5,543			1,019			212,657
Conversion of Class B and C to common units		-			120,663			(60,671	)		(59,992	)		-			-			-			-			-
Issuance of common units for acquisition		-			19,724			-			-			-			-			-			-			19,724
Issuance of common units		-			353,446			-			-			-			-			-			-			353,446
Issuance of restricted common units		-			-			-			-			-			-			-			-			-
Forfeitures of restricted common units		-			-			-			-			-			-			-			-			-
Exercise of common unit options		-			100			-			-			-			-			-			-			100
Unit based compensation expenses		-			15,534			-			-			-			-			-			-			15,534
General partner contributions		-			-			-			-			-			-			7,735			-			7,735
Partner distributions		-			(49,296	)		-			-			-			(29,038	)		(1,599	)		-			(79,933	)
Acquisition of FrontStreet		-			-			-			-			83,448			-			-			-			83,448
FrontStreet contributions		-			-			-			-			13,417			-			-			-			13,417
FrontStreet distributions		-			-			-			-			(9,695	)		-			-			-			(9,695	)
Net (loss) income		-			(12,037	)		-			-			5,792			(7,198	)		(393	)		-			(13,836	)
Other		-			25			-			-			-			15			-			-			40
Net hedging activity reclassified to earnings		-			-			-			-			-			-			-			19,362			19,362
Net change in fair value of cash flow hedges		-			-			-			-			-			-			-			(58,706	)		(58,706	)
Balance - December 31, 2007	$	-		$	490,351		$	-		$	-		$	92,962		$	7,019		$	11,286		$	(38,325	)	$	563,293

See accompanying notes to consolidated financial statements

Exhibit 99.4 - 8

Regency Energy Partners LP

Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

Organization.The consolidated financial statements presented herein contain the results of Regency Energy Partners LP (“Partnership”), a Delaware limited partnership, and its predecessor, Regency Gas Services LLC (“Predecessor”).  The Partnership was formed on September 8, 2005; on February 3, 2006, in conjunction with its initial public offering of securities (“IPO”), the Predecessor was converted to a limited partnership Regency Gas Services LP (“RGS”) and became a wholly owned subsidiary of the Partnership.  The Partnership and its subsidiaries are engaged in the business of gathering, treating, processing, transporting, and marketing natural gas and natural gas liquids (“NGLs”). Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.

On August 15, 2006, the Partnership acquired all the outstanding equity of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC (collectively “TexStar”), from HMTF Gas Partners II, L.P. (“HMTF Gas Partners”), an affiliate of HM Capital Partners LLC (“HM Capital Partners”) (“TexStar Acquisition”). Because the TexStar Acquisition was a transaction between commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner similar to a pooling of interests. Information included in these financial statements is presented as if the Partnership and TexStar had been combined throughout the periods presented in which common control existed, December 1, 2004 forward.

On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of GECC, acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners. Concurrently, Regency LP Acquirer LP, another indirect subsidiary of GECC, acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management team. As a part of this acquisition, affiliates of HM Capital Partners entered into an agreement to hold 4,692,417 of the Partnership’s common units for a period of 180 days. In addition, a separate affiliate of HM Capital Partners entered into an agreement to hold 3,406,099 of the Partnership’s common units for a period of one year.

GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of GE. For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.”  Concurrent with the Partnership's issuance of common units in July and August 2007, GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $7,735,000 to maintain the General Partner’s two percent interest in the Partnership.

Concurrent with the GE EFS acquisition, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units for a total consideration of $24.00 per unit.  Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

The Partnership was not required to record any adjustments to reflect GE EFS’s acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).

Basis of Presentation.The consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been reclassified to conform to current year’s presentation.

The accompanying consolidated financial statements include the assets, liabilities, results of operations and cash flows of the Partnership and its wholly owned subsidiaries. The Partnership operates and manages its business as two reportable segments: a) gathering and processing, and b) transportation as of December 31, 2007.

Exhibit 99.4 - 9

Acquisition of FrontStreet Hugoton, LLC.  On January 7, 2008, the Partnership acquired all of the outstanding equity and minority interest (the “FrontStreet Acquisition”) of FrontStreet Hugoton, LLC (“FrontStreet”) from ASC Hugoton LLC, (“ASC”), and FrontStreet EnergyOne LLC, (“EnergyOne” and, together with ASC, the “Sellers”). FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.  As a result of the acquisition, the Partnership increased its presence in the Midcontinent region, adding predictable, fee-based revenue to its gathering and processing segment.

The total purchase price consisted of (a) 4,701,034 Class E common units of the Partnership issued to ASC in exchange for its 95 percent interest and (b) the payment of $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract which was valued at $3,888,000.  RGS financed the cash portion of the purchase price out of its revolving credit facility.  The transaction is subject to customary post-closing adjustments.

The as-if pooling treatment resulted in an increase in revenues of $22,184,000 for the year ended December 31, 2007 compared to the prior reported balance, and a decrease of $6,097,000 in net loss for the same period. 

In connection with the FrontStreet Acquisition, the General Partner entered into Amendment No. 3 to the Amended and Restated Agreement of Limited Partnership of the Partnership, which created the Partnership’s Class E common units. The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units are not entitled to participate in earnings or distributions of operating surplus by the Partnership. The Class E common units were issued in a private offering conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 as afforded by Section 4(2) thereof. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

Because the acquisition of ASC’s 95 percent interest is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method. Under this method of accounting, the Partnership will reflect historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities. Further, certain transaction costs that would normally be capitalized were expensed.  The Partnership recast the December 31, 2007 balance sheet and, for the year ended December 31, 2007, its statement of operations and cash flows to reflect the as-if pooling accounting treatment of this acquisition, effective as of the date of common control of June 18, 2007.

Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which the Partnership will apply the purchase method of accounting.  The Partnership is in the process of obtaining third-party valuations of long-lived and certain intangible assets; thus, the allocation of the purchase price is subject to refinement.

The following table summarizes the book values of the assets acquired and liabilities assumed at the date of common control, following the as-if pooled method of accounting.

	At June 18, 2007
	(in thousands)
Current assets	$	8,840
Property, plant and equipment		91,556
Total assets acquired		100,396
Current liabilities		(12,556	)
Net book value of assets acquired	$	87,840

Exhibit 99.4 - 10

2.  Summary of Significant Accounting Policies

Use of Estimates.  These consolidated financial statements have been prepared in conformity with GAAP which necessarily include the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements.  Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

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

Restricted Cash.  Restricted cash of $6,029,000 is held in escrow for environmental remediation projects pursuant to an escrow agreement.  A third-party agent invests funds held in escrow in US Treasury securities.  Interest earned on the investment is credited to the escrow account.

Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired.  Sales or retirements of assets, along with the related accumulated depreciation, are included in operating income unless the disposition is treated as discontinued operations.  Gas to maintain pipeline minimum pressures is capitalized and classified as property, plant, and equipment.  Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the year ended December 31, 2007, 2006, and 2005, the Partnership capitalized interest of $1,754,000, $511,000, and $2,613,000, respectively. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.  Expenditures to extend the useful lives of the assets are capitalized.

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

The Partnership accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” and FIN 47 “Accounting for Conditional Asset Retirement Obligations.” These accounting standards require the Partnership to recognize on its balance sheet the net present value of any legally binding obligation to remove or remediate the physical assets that it retires from service, as well as any similar obligations for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Partnership.  While the Partnership is obligated under contractual agreements to remove certain facilities upon their retirement, management is unable to reasonably determine the fair value of such asset retirement obligations because the settlement dates, or ranges thereof, were indeterminable and could range up to 95 years, and the undiscounted amounts are immaterial.  An asset retirement obligation will be recorded in the periods wherein management can reasonably determine the settlement dates.

Depreciation expense related to property, plant and equipment was $50,719,000, $36,880,000, and $21,191,000 for the years ended December 31, 2007, 2006, and 2005, respectively. Depreciation of plant and equipment is recorded on a straight-line basis over the following estimated useful lives.

Functional Class of Property	Useful Lives (Years)
Gathering and Transmission Systems	5 - 20
Gas Plants and Buildings	15 - 35
Other property, plant and equipment	3 - 10

Exhibit 99.4 - 11

Intangible Assets. Intangible assets consisting of (i) permits and licenses and (ii) customer contracts are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows.  The value of the permits and licenses was determined by discounting the income associated with activities that would be lost over the period required to replace these permits and their estimated useful life is fifteen years.  The Partnership renegotiated a number of significant customer contracts and the value of customer contracts was determined by using a discounted cash flow model.  The estimated useful lives range from three to thirty years.

The Partnership evaluates the carrying value of intangible assets whenever certain events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable.  In assessing the recoverability, the Partnership compares the carrying value to the undiscounted future cash flows the intangible assets are expected to generate.  If the total of the undiscounted future cash flows is less than the carrying amount of the intangible assets, the intangibles are written down to their fair value.  The Partnership did not record any impairment in 2007, 2006, or 2005.

Goodwill.Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination.  Goodwill is allocated to two reportable segments, Gathering and Processing and Transportation.  Goodwill is not amortized, but is tested for impairment annually based on the carrying values as of December 31, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Impairment occurs when the carrying amount of a reporting unit exceeds it fair value.  At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.  To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as to revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership’s most recent forecast.  No impairment was indicated for the years ended December 31, 2007, 2006 or 2005.

Investment in Unconsolidated Investee.Investments in entities for which the Partnership has significant influence over the investee’s operating and financial policies, but less than a controlling interest, are accounted for using the equity method.  Under the equity method, the Partnership’s investment in an investee is included in the consolidated balance sheets under the caption investments in unconsolidated investee and the Partnership’s share of the investee’s earnings or loss is included in the consolidated statements of operations under the caption other income and deductions, net.  All of the Partnership’s investments are subject to periodic impairment review.  The impairment analysis requires significant judgment to identify events or circumstances that would likely have significant adverse effect on the future use of the investment. The Partnership purchased the remaining minority interest in its sole unconsolidated investee in February 2007.

Other Assets, netOther assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt.

Gas Imbalances.Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as other current assets or other current liabilities using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system pursuant to imbalance agreements for which settlement prices are not contractually established.  Within certain volumetric limits determined at the sole discretion of the creditor, these imbalances are generally settled by deliveries of natural gas.  Imbalance receivables and payables as of December 31, 2007 and 2006 were immaterial.

Minority Interest.  The December 31, 2007 financial statements reflect the 5 percent minority interest of FrontStreet as of December 31, 2007.

Exhibit 99.4 - 12

Revenue Recognition.The Partnership earns revenues from (i) domestic sales of natural gas, NGLs and condensate and (ii) natural gas gathering, processing and transportation.  Revenues associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs.  Revenues associated with transportation and processing fees are recognized when the service is provided.  For gathering and processing services, the Partnership receives either fees or commodities from natural gas producers depending on the type of contract.  Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above.  Under the percentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas.  Under the percentage-of-index contract type, the Partnership earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties.  The Partnership generally reports revenues gross in the consolidated statements of operations, in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based agreements, the Partnership acts as the principal in these transactions, takes title to the product, and incurs the risks and rewards of ownership.

Risk Management Activities.  The Partnership’s net income and cash flows are subject to volatility stemming from changes in market prices such as natural gas prices, natural gas liquids prices, and processing margins. The Partnership uses ethane, propane, butane, natural gasoline, and condensate swaps to create offsetting positions to specific commodity rate exposures. Prior to July 1, 2005, derivative financial instruments were not designated for hedge accounting and the changes in fair value of these contracts were marked to market and unrealized gains and losses were recorded in revenue. Subsequent to July 1, 2005, the Partnership accounts for derivative financial instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS No. 133”), whereby all derivative financial instruments were recorded in the balance sheet at their fair value on a net basis by settlement date. The Partnership employs derivative financial instruments in connection with an underlying asset, liability and/or anticipated transaction and not for speculative purposes. Derivative financial instruments qualifying for hedge accounting treatment have been designated by the Partnership as cash flow hedges. The Partnership enters into cash flow hedges to hedge the variability in cash flows related to a forecasted transaction.

At inception, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing correlation and hedge effectiveness. The Partnership also assesses, both at the inception of the hedge and on an on-going basis, whether the derivatives are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, the Partnership regularly assesses the creditworthiness of counterparties to manage against the risk of default.  If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.  For cash flow hedges, changes in the derivative fair values, to the extent that the hedges are effective, are recorded as a component of accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge’s change in value is recognized immediately in earnings.  In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions. For the Partnership’s derivative financial instruments that were not designated for hedge accounting, the change in market value is recorded as a component of net unrealized and realized loss from risk management activities in the consolidated statements of operations.

Benefits. The Partnership provides a portion of medical, dental, and other healthcare benefits to employees. Commencing on June 1, 2005, the Partnership provides a matching contribution for employee contributions to their 401(k) accounts, which vests immediately.  The amount of matching contributions for the years ended December 31, 2007, 2006, and 2005 was $469,000, $201,000, and $100,000, respectively, and is recorded in general and administrative expenses.  The Partnership has no pension obligations or other post employment benefits.

Exhibit 99.4 - 13

Income Taxes.The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. Effective January 1, 2007, the Partnership became subject to the gross margin tax enacted by the state of Texas on May 1, 2006. The Partnership has wholly-owned subsidiaries that are subject to income tax and provides for deferred income taxes using the asset and liability method for these entities. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership’s deferred tax liability of $8,642,000 as of December 31, 2007 relates to the difference between the book and tax basis of property, plant, and equipment and intangible assets and is included in other long-term liabilities in the accompanying consolidated balance sheet. The Partnership adopted the provisions of FIN No. 48 “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement 109”, on January 1, 2007. Upon adoption, the Partnership did not identify or record any uncertain tax positions not meeting the more likely than not standard. The Partnership’s entities that are required to pay federal income tax recognized current income tax expense ($1,171,000) and deferred income tax benefit ($240,000) using a 35.325 percent effective rate.

Equity-Based Compensation.The Partnership adopted SFAS 123(R) “Share-Based Payment” in the first quarter of 2006 upon the creation of the long-term incentive plan (“LTIP”).  The adoption had no impact on the consolidated financial position, result of operations or cash flows as no LTIP awards were granted prior to adoption.

Earnings per unit.Earnings per unit information has not been presented for periods prior to the IPO. Basic net income per limited partner unit is computed in accordance with SFAS No. 128, “Earnings Per Share”, as interpreted by Emerging Issues Task Force (“EITF”) Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class method under FASB Statement No. 128.” After deducting the general partners’ interest in net income or loss which may consist of its 2 percent interest, made whole for any losses allocated in a prior year or incentive distribution rights, the limited partners’ interest in the remaining net income or loss is allocated to each class of equity units based on declared distributions and then divided by the weighted average number of units outstanding in each class of security. In periods when the Partnership’s aggregate net income exceeds the aggregate distributions, EITF 03-6 requires the Partnership to present earnings per unit as if all of the earnings for the periods were distributed. Diluted net income per limited partner unit is computed by dividing limited partners’ interest in net income, after deducting the general partner’s interest, by the weighted average number of common and subordinated units outstanding and the effect of nonvested restricted units and unit options computed using the treasury stock method. Common and subordinated units are considered to be a single class.

Recently Issued Accounting Standards. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever another standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, except for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis when the effective date is fiscal years beginning after November 15, 2008. Disclosures under SFAS 157 were not deferred. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

In January 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115” (“SFAS 159”), which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

On December 4, 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS No. 141R”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. SFAS No. 141R is effective for fiscal years beginning after December 15, 2008. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

Exhibit 99.4 - 14

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”), which will significantly change the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

3. Partners’ Capital and Distributions

Initial Public Offering. On February 3, 2006, the Partnership offered and sold 13,750,000 common units, representing a 35.3 percent limited partner interest in the Partnership, in its IPO, at a price of $20.00 per unit.  Total proceeds from the sale of the units were $275,000,000, before offering costs and underwriting commissions. On March 8, 2006, the Partnership sold an additional 1,400,000 common units at a price of $20.00 per unit as the underwriters exercised a portion of their over allotment option.

Class B Common Units. On August 15, 2006, in connection with the TexStar Acquisition, the Partnership issued 5,173,189 of Class B common units to HMTF Gas Partners as partial consideration for the TexStar Acquisition. The Class B common units had the same terms and conditions as the Partnership’s common units, except that the Class B common units were not entitled to participate in earnings or distributions by the Partnership. The Class B common units were converted into common units without the payment of further consideration on a one-for-one basis on February 15, 2007.

Class C Common Units. On September 21, 2006, the Partnership entered into a Class C Unit Purchase Agreement with certain purchasers, pursuant to which the purchasers purchased 2,857,143 Class C common units representing limited partner interests in the Partnership at a price of $21.00 per unit. The Class C common units had the same terms and conditions as the Partnership’s common units, except that the Class C common units were not entitled to participate in earnings or distributions by the Partnership. The Class C common units were converted into common units without the payment of further consideration on a one-for-one basis on February 8, 2007.

Class E Common Units.  On January 7, 2008, the Partnership issued Class E common units as partial consideration for the FrontStreet Acquisition.  The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units were not entitled to participate in earnings or distributions by the Partnership.  Income, contributions, and distributions of FrontStreet are presented as Class E common unit activity.

2007 Equity Offering. On July 26, 2007, the Partnership sold 10,000,000 common units for $32.05 per unit. After deducting underwriting discounts and commissions of $12,820,000, the Partnership received $307,680,000 from this sale, excluding the general partner’s proportionate capital contribution of $6,279,000 and offering expenses of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 for $32.05 as the underwriters exercised their option to purchase additional units. The Partnership received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000. The Partnership used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000).  With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership repurchased $192,500,000, or 35 percent, of its outstanding senior notes which required the Partnership to pay an early redemption penalty of $16,122,000 in August 2007.

Distributions. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of the Partnership’s Available Cash (defined below) to unitholders of record on the applicable record date, as determined by the general partner.

Available Cash.Available Cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

Exhibit 99.4 - 15

General Partner Interest and Incentive Distribution Rights. The general partner is entitled to 2 percent of all quarterly distributions that the Partnership makes prior to its liquidation.  This general partner interest is represented by 1,216,710 equivalent units as of December 31, 2007.  The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial 2 percent interest in these distributions will be reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2 percent general partner interest.

The incentive distribution rights held by the general partner entitles it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved.  The general partner’s incentive distribution rights are not reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2 percent general partner interest.  Please read the Distributions of Available Cash during the Subordination Period and Distributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Subordinated Units.All of the subordinated units are held by GE EFS and members of senior management.  The partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the “Minimum Quarterly Distribution,” plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters.  Furthermore, no arrearages will be paid on the subordinated units.  The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units.  The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met.  The earliest date at which the subordination period may end is December 31, 2008. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.

Distributions of Available Cash during the Subordination Period.The partnership agreement requires that we make distributions of Available Cash for any quarter during the subordination period in the following manner:

·   first, 98 percent to the common unitholders, pro rata, and 2 percent to the general partner, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;

·   second, 98 percent to the common unitholders, pro rata, and 2 percent to the general partner, until we distribute for each

·   outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;

·   third, 98 percent to the subordinated unitholders, pro rata, and 2 percent to the general partner, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;

·   fourth, 98 percent to all unitholders, pro rata, and 2 percent to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter;

·   fifth, 85 percent to all unitholders, pro rata, and 15 percent to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter;

·   sixth, 75 percent to all unitholders, pro rata, and 25 percent to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and

·   thereafter, 50 percent to all unitholders, pro rata, and 50 percent to the general partner.

Exhibit 99.4 - 16

Distributions of Available Cash after the Subordination Period. The Partnership Agreement requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

§   first, 98 percent to all unitholders, pro rata, and 2 percent to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter;

§   second, 85 percent to all unitholders, pro rata, and 15 percent to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter;

§   third, 75 percent to all unitholders, pro rata, and 25 percent to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and

§   thereafter, 50 percent to all unitholders, pro rata, and 50 percent to the general partner.

Distributions. The Partnership made the following cash distributions during the years ended December 31, 2007 and 2006:

Distribution Date	Cash Distributions
2006	(per unit)
May 15, 2006	$	0.2217
August 14, 2006		0.3500
November 14, 2006		0.3700
2007
Feburary 14, 2007	$	0.3700
May 15, 2007		0.3800
August 14, 2007		0.3800
November 14, 2007		0.3900

FrontStreet made distributions of $13,417,000 from June 18, 2007 to December 31, 2007.

4. Loss per Limited Partner Unit

Loss per unit for the year ended December 31, 2006 reflects only the eleven months since the closing of the Partnership’s IPO on February 3, 2006. For convenience, January 31, 2006 has been used as the date of the change in ownership. Accordingly, results for January 2006 have been excluded from the calculation of loss per unit. While the non-vested (or restricted) units are deemed to be outstanding for legal purposes, they have been excluded from the calculation of basic loss per unit in accordance with SFAS No. 128.

The following data show the number of potential dilutive common units that were excluded from the loss per unit calculation.

	December 31, 2007		December 31, 2006
Restricted common units		397,500		516,500
Common unit options		738,668		909,600

Restricted common units generally vest at the rate of one-fourth of the total grant per year. A significant portion of the restricted units outstanding at December 31, 2007 were granted on June 18, 2007 upon the acquisition by GE EFS of a controlling interest in the Partnership. All of the restricted units outstanding at December 31, 2006 that remained outstanding at the time of the GE EFS Acquisition vested upon the change in control of the Partnership, converting to common units on a one-to-one basis.

Subsequent to the GE EFS Acquisition, the outstanding common unit options immediately vested. These options generally expire ten years after the grant date. The options were granted with a strike price equal to the grant date closing price of the Partnership’s common units.  As of December 31, 2007, the Partnership had not granted any new options following the GE EFS Acquisition.

Exhibit 99.4 - 17

In accordance with SFAS No. 128, the Partnership allocates net income or loss to each class of equity security in proportion to the amount of income earned during that period after deducting distributions. Because the Class B common units used in the TexStar Acquisition were deemed to be outstanding for all periods presented, a portion of net income or loss was allocated to this class of equity in periods where they were not expressly prohibited from receiving distributions. The Partnership issued Class D and Class E common units in January 2008 and these securities are described in the subsequent events footnote.

The Partnership Agreement requires that the general partner shall receive a 100 percent allocation of income until its capital account is made whole for all of the net losses allocated to it in prior years.

Subsequent to the issuance of its consolidated financial statements for the year ended December 31, 2006, the Partnership identified an error in the calculation of earnings per unit resulting from the issuance of Class C common units at a discount. At the commitment date to sell the Class C common units the purchase price of $21.00 per unit represented a $1.74 discount from the fair value of the Partnership’s common units. Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,” the discount represented a beneficial conversion feature (“BCF”) that should have been treated as a non-cash distribution for purposes of calculating earnings per unit. The BCF is reflected in loss per unit using the effective yield method over the period the Class C common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class C common units” for the years ended December 31, 2007 and 2006. The error is immaterial and had no impact on the Partnership’s net loss or partners’ capital.

The following table depicts the effect on earnings per unit for the year ended December 31, 2006.

	As Previously
	Reported			As Restated
		(in thousands except for units and per unit data)
NET LOSS	$	(7,244	)	$	(7,244	)
Less: Net income from January 1-31, 2006		1,564			1,564
Net loss for partners		(8,808	)		(8,808	)
General partner's interest		(176	)		(176	)
Beneficial conversion feature for Class C common units		-			3,587
Limited partners' interest	$	(8,632	)	$	(12,219	)
Basic and diluted earnings per unit:
Amount allocated to common and subordinated units	$	(8,006	)	$	(11,333	)
Weighted average number of common and subordinated units outstanding		38,207,792			38,207,792
Loss per common and subordinated unit	$	(0.21	)	$	(0.30	)
Distributions per unit	$	0.94		$	0.94
Amount allocated to Class B common units	$	(626	)	$	(886	)
Weighted average number of Class B common units outstanding		5,173,189			5,173,189
Loss per Class B common unit	$	(0.12	)	$	(0.17	)
Distributions per unit	$	-		$	-
Amount allocated to Class C common units	$	-		$	3,587
Total Class C common units outstanding		871,817			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	-		$	1.26
Distributions per unit	$	-		$	-

5. Acquisitions and Dispositions

2007

Palafox Joint Venture. The Partnership acquired the outstanding interest in the Palafox Joint Venture not owned (50 percent) for $5,000,000 effective February 1, 2007. The Partnership allocated $10,057,000 to gathering and transmission systems in the three months ended March 31, 2007. The allocated amount consists of the investment in unconsolidated subsidiary of $5,650,000 immediately prior to the Partnership’s acquisition and the Partnership’s $5,000,000 purchase of the remaining interest offset by $593,000 of working capital accounts acquired.

Exhibit 99.4 - 18

Significant Asset Dispositions. The Partnership sold selected non-core pipelines, related rights of way and contracts located in south Texas for $5,340,000 on March 31, 2007 and recorded a loss on sale of $1,808,000.  Additionally, the Partnership sold two small gathering systems and associated contracts located in the Midcontinent region for $1,750,000 on May 31, 2007 and recorded a loss on the sale of $469,000.  The Partnership also sold its 34 mile NGL pipeline located in east Texas for $3,000,000 on June 29, 2007 and simultaneously entered into transportation and operating agreements with the buyer. The Partnership accounted for this transaction as a sale-leaseback whereby the $3,000,000 gain was deferred and will be amortized to earnings over a twenty year period. The Partnership recorded $3,000,000 in gathering and transmission systems and the related obligations under capital lease. On August 31, 2007, the Partnership sold an idle processing plant for $1,300,000 and recorded a $740,000 gain.

Acquisition of Pueblo Midstream Gas Corporation. On April 2, 2007, the Partnership and its indirect wholly-owned subsidiary, Pueblo Holdings, Inc., a Delaware corporation (“Pueblo Holdings”), entered into a definitive Stock Purchase Agreement (the “Stock Purchase Agreement”) with Bear Cub Investments, LLC, a Colorado limited liability company, the members of that company (the  “Members”) and Robert J. Clark, as Sellers’ Representative, pursuant to which the Partnership and Pueblo Holdings on that date acquired all the outstanding equity of Pueblo Midstream Gas Corporation, a Texas corporation (“Pueblo”), from the Members (the “Pueblo Acquisition”). Pueblo owned and operated natural gas gathering, treating and processing assets located in south Texas. These assets are comprised of a 75 MMcf/d gas processing and treating facility, 33 miles of gathering pipelines and approximately 6,000 horsepower of compression.

The purchase price for the Pueblo Acquisition consisted of (1) the issuance of 751,597 common units of the Partnership to the Members, valued at $19,724,000 and (2) the payment of $34,855,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $108,000.  The cash portion of the consideration was financed out of the proceeds of the Partnership’s revolving credit facility.

The Pueblo Acquisition offers the opportunity to reroute gas to one of the Partnership’s existing gas processing plants which is expected to provide cost savings.  The total purchase price was allocated preliminarily as follows based on estimates of the fair values of assets acquired and liabilities assumed.

	At April 2, 2007
		(in thousands)
Current Assets	$	1,295
Gas Plants and buildings		8,994
Gathering and transmission systems		13,079
Other property, plant and equipment		180
Intangible assets subject to amortization (contracts)		5,242
Goodwill		36,523
Total assets required	$	65,313
Current liablities		(1,187	)
Long-term liablities		(9,492	)
Total purchase price	$	54,634

2006

TexStar.  On August 15, 2006, the Partnership acquired all the outstanding equity of TexStar by issuing 5,173,189 Class B common units valued at $119,183,000, a cash payment of $62,074,000 and the assumption of $167,652,000 of TexStar’s outstanding bank debt.  Because the TexStar Acquisition is a transaction between commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner similar to a pooling of interests.  As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows from the date common control began (December 1, 2004) forward.

Exhibit 99.4 - 19

The following table presents the revenues and net income for the previously separate entities and the combined amounts presented in these audited consolidated financial statements.

	Year Ended December 31,
	2006			2005
Revenue	(in thousands)
Regency Energy Partners	$	812,564		$	692,603
TexStar Field Services		84,301			16,798
Combined	$	896,865		$	709,401
Net income (loss)
Regency Energy Partners	$	(1,639	)	$	(11,224	)
TexStar Field Services		(5,605	)		364
Combined	$	(7,244	)	$	(10,860	)

Como.  On July 25, 2006, TexStar consummated an Asset Purchase and Sale Agreement (the “Como Acquisition Agreement”) dated June 16, 2006 with Valence Midstream, Ltd. and EEC Midstream, Ltd., under which TexStar acquired certain natural gas gathering, treating and processing assets from the other parties thereto for $81,695,000 including transaction costs.  The assets acquired consisted of approximately 59 miles of pipelines and certain specified contracts (the “Como Assets”).  The results of operations of the Como Assets have been included in the statements of operations beginning July 26, 2006.  The Partnership’s purchase price allocation resulted in $18,493,000 being allocated to property, plant and equipment and $63,202,000 being allocated to intangible assets.

2005

Enbridge. TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in east and south Texas (the “Enbridge Assets”) from Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Intrastate), LP and Enbridge Pipelines (Texas Gathering), LP (collectively “Enbridge”) for $108,282,000 inclusive of transaction expenses on December 7, 2005 (the “Enbridge Acquisition”).  The Enbridge Acquisition was accounted for using the purchase method of accounting.  For convenience, the results of operations of the Enbridge Assets are included in the statements of operations beginning December 1, 2005.  The purchase price was allocated to gas plants and buildings ($42,361,000), gathering and transmission systems ($65,002,000), and other property, plant and equipment ($919,000) as of December 1, 2005.  TexStar assumed no material liabilities in this acquisition.

Other 2005 Acquisitions. The Partnership made several other asset acquisitions during the year ended December 31, 2005.  These individually immaterial acquisitions, when aggregated, are not material to the financial position or results of operations of the Partnership.

Regency Gas Treating LP. On May 2, 2005, the Partnership sold the assets of Regency Gas Treating LP for $6,000,000. After the allocation of $977,000 of goodwill, the resulting gain was $626,000. The Partnership treated this sale as a discontinued operation. The equipment lease revenue, operating income, and net income for the year ended December 31, 2005 was $335,000, $186,000, and $732,000, respectively.

The following unaudited pro forma financial information has been prepared for Pueblo, Como and Enbridge. The pro forma amounts include certain adjustments to historical results of operations including depreciation and amortization expense (based upon the estimated fair values and useful lives of property, plant and equipment).  Such unaudited pro forma information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.

Exhibit 99.4 - 20

	Pro Forma Year Ended December 31,
	2007			2006			2005
	(in thousands except unit and per unit data)
Revenues	$	1,193,959		$	952,229		$	836,809
Net loss		(13,527	)		(6,876	)		(10,784	)
Less net income from January 1-31, 2006		-			1,564
Net loss for partners		(13,527	)		(8,440	)
General partner's equity ownership		(386	)		(169	)
Beneficial conversion feature for Class C common units		1,385			3,587
Limited partners' interest in net loss	$	(14,526	)	$	(11,858	)
Net loss allocated to common and subordinated units	$	(14,526	)	$	(10,999	)
Weighted average common and subordinated units – basic and diluted		51,056,769			38,207,792
Loss per common units - basic and diluted	$	(0.28	)	$	(0.29	)
Distributions per unit	$	1.52		$	0.9417
Net loss allocated to Class B common units	$	-		$	(859	)
Weighted average Class B common units outstanding		651,964			5,173,189
Loss per Class B common units - basic and diluted	$	-		$	(0.17	)
Distributions per unit	$	-		$	-
Amount allocated to Class C units	$	1,385		$	3,587
Total Class C common units outstanding		2,857,143			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	0.48		$	1.26
Distributions per unit	$	-		$	-
Amount allocated to Class E units	$	5,792		$	-
Total Class E common units outstanding		4,701,034			-
Income per Class E common unit	$	1.23		$	-
Distributions per unit	$	2.06		$	-

6. Risk Management Activities

Effective June 19, 2007, the Partnership elected to account for our entire outstanding commodity hedging instruments on a mark-to-market basis except for the portion of commodity hedging instruments where all NGLs products for a particular year were hedged and the hedging relationship was effective. As a result, a portion of commodity hedging instruments is and will continue to be accounted for using mark-to-market accounting until all NGLs products are hedged for an individual year and the hedging relationship is deemed effective. During the year ended December 31, 2007, the Partnership recorded $14,559,000 of mark-to-market losses for certain hedges that do not qualify for hedge accounting.

The Partnership’s hedging positions reduce exposure to variability of future commodity prices through 2009.  The net fair value of the Partnership’s risk management activities constituted a net liability and a net asset of $52,925,000 and $8,000 as of December 31, 2007 and 2006, respectively.  The Partnership expects to reclassify $36,171,000 of hedging losses as an offset to revenues from accumulated other comprehensive income (loss) in the next twelve months.  The Partnership recognized immaterial gains related to hedged forecasted transactions that did not occur by the end of the originally specified period and recognized $486,000 of ineffectiveness during the year ended December 31, 2007.

Upon the early termination of an interest rate swap with a notional debt amount of $200,000,000 that was effective from April 2007 through March 2009, the Partnership received $3,550,000 in cash from the counterparty.  The Partnership reclassified $1,078,000 and $2,663,000 from accumulated other comprehensive income (loss), reducing interest expense, net in the years ended December 31, 2007 and 2006,respectively, because the hedged forecasted transaction will not occur.

Prior to the election of hedge accounting on July 1, 2005, realized and unrealized losses of $16,226,000 were recorded as a charge against revenue.

Exhibit 99.4 - 21

7. Long-term Debt

Obligations in the form of senior notes, and borrowings under the credit facilities are as follows.

	December 31, 2007			December 31, 2006
	(in thousands)
Senior notes	$	357,500		$	550,000
Term loans		-			50,000
Revolving loans		124,000			64,700
Total		481,500			664,700
Less: current portion		-			-
Long-term debt	$	481,500		$	664,700
Availability under term and revolving credit facility
Total credit facility limit	$	500,000		$	300,000
Term loans		-			(50,000	)
Revolver loans		(124,000	)		(64,700	)
Letters of credit		(27,263	)		(5,183	)
Total available	$	348,737		$	180,117

Long-term debt maturities as of December 31, 2007 for each of the next five years are as follows.

Year ending December 31,	Amount
	(in thousands)
2008	$	-
2009		-
2010		-
2011		124,000
2012		-
Thereafter		357,500
Total	$	481,500

The Partnership borrowed and repaid $238,230,000 and $421,430,000, respectively, in the year ended December 31, 2007 under the revolving credit facility. The borrowings were made primarily to fund capital expenditures and proceeds from the equity offering were used to repay amounts outstanding under the revolving credit facility. During the year ended December 31, 2006 the Partnership borrowed $195,300,000 under the revolving credit facility, primarily to fund capital expenditures and temporarily finance the TexStar Acquisition.  During the same period, it repaid $180,600,000 of these borrowings with the proceeds from term loans and private equity offering proceeds.

Exhibit 99.4 - 22

Senior Notes. In 2006, the Partnership and Regency Energy Finance Corp. (“Finance Corp”), a wholly-owned subsidiary of RGS, issued $550,000,000 senior notes that mature on December 15, 2013 in a private placement (“senior notes”). The senior notes bear interest at 8.375 percent and interest is payable semi-annually in arrears on each June 15 and December 15. In August 2007, the Partnership exercised its option to redeem 35 percent or $192,500,000 of its outstanding senior notes on or before December 15, 2009. Under the senior notes terms, no further redemptions are permitted until December 15, 2010. The Partnership made the redemption at a price of 108.375 percent of the principal amount plus accrued interest. Accordingly, a redemption premium of $16,122,000 was recorded as loss on debt refinancing and unamortized loan origination costs of $4,575,000 were written off and charged to loss on debt refinancing in the year ended December 31, 2007. A portion of the proceeds of an equity offering was used to redeem the senior notes. In September 2007, the Partnership exchanged its then outstanding 8 3/8 percent senior notes which were not registered under the Securities Act of 1933 for senior notes with identical terms that have been so registered.

The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees.  The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s Credit Facility, to the extent of the value of the assets securing such obligations.

The senior notes are guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”) as of December 31, 2007, except for certain wholly-owned subsidiaries of the Partnership.  These note guarantees are the joint and several obligations of the Guarantors.  A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets if such sale would cause a default under the terms of the senior notes.  Events of default include nonpayment of principal or interest when due; failure to make a change of control offer (explained below); failure to comply with reporting requirements according to SEC rules and regulations; and defaults on the payment of obligations under other mortgages or indentures.  Since certain wholly-owned subsidiaries do no guarantee the senior notes, the consolidating financial statements of the guarantors and non-guarantors for the year-end December 31, 2007 are disclosed below.

Balance Sheet
For the Year Ended December 31, 2007 (in thousands)
	Guarantors		Non Guarantors		Eliminations			Consolidated
ASSETS
Total current assets	$	170,415	$	9,478	$	-		$	179,893
Property, plant and equipment, net		818,054		95,055		-			913,109
Total other assets		185,408		-		-			185,408
TOTAL ASSETS	$	1,173,877	$	104,533	$	-		$	1,278,410
LIABILITIES & PARTNERS' CAPITAL
Total current liabilities	$	191,580	$	6,678	$	-		$	198,258
Long-term liabilities from risk management activities		15,073		-		-			15,073
Other long-term liabilities		15,393		-		-			15,393
Long-term debt		481,500		-		-			481,500
Minority interest		-		-		4,893			4,893
Partners' capital		470,331		97,855		(4,893	)		563,293
TOTAL LIABILITIES & PARTNERS' CAPITAL	$	1,173,877	$	104,533	$	-		$	1,278,410

Exhibit 99.4 - 23

Statement of Operations
For the year ended December 31, 2007 (in thousands except unit data)
	Guarantors			Non Guarantors			Eliminations		Consolidated
Total revenues	$	1,168,054		$	22,184		$	-	$	1,190,238
Total operating costs and expenses		1,114,843			16,031			-		1,130,874
OPERATING INCOME		53,211			6,153			-		59,364
Interest expense, net		(52,016	)		-			-		(52,016	)
Loss on debt refinancing		(21,200	)		-			-		(21,200	)
Other income and deductions, net		1,308			(56	)		-		1,252
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST		(18,697	)		6,097			-		(12,600	)
Income tax expense		931			-			-		931
Minority interest in net income from subsidairy					305			-		305
NET INCOME (LOSS)	$	(19,628	)	$	5,792		$	-	$	(13,836	)
General partner's interest		(393	)		-			-		(393	)
Beneficial conversion feature for Class C common units		1,385			-			-		1,385
Limited partners' interest	$	(20,620	)	$	5,792		$	-	$	(14,828	)
Basic and diluted earnings per unit:
Amount allocated to common and subordinated units	$	(20,620	)	$	-		$	-	$	(20,620	)
Weighted average number of common and subordinated units outstanding		51,056,769			-			-		51,056,769
Loss per common and subordinated unit	$	(0.40	)	$	-		$	-	$	(0.40	)
Distributions per unit	$	1.52		$	-		$	-	$	1.52
Amount allocated to Class B common units	$	-		$	-		$	-	$	-
Weighted average number of Class B common units outstanding		651,964			-			-		651,964
Loss per Class B common unit	$	-		$	-		$	-	$	-
Distributions per unit	$	-		$	-		$	-	$	-
Amount allocated to Class C common units	$	1,385		$	-		$	-	$	1,385
Total Class C common units outstanding		2,857,143			-			-		2,857,143
Income per Class C common unit due to beneficial conversion feature	$	0.48		$	-		$	-	$	0.48
Distributions per unit	$	-		$	-		$	-	$	-
Amount allocated to Class E common units	$	-		$	5,792		$	-	$	5,792
Total Class E common units outstanding		-			4,701,034			-		4,701,034
Income per Class E common unit	$	-		$	1.23		$	-	$	1.23
Distributions per unit	$	-		$	2.06		$	-	$	2.06

Statement of Cash Flow
For the year ended December 31, 2007 (in thousands)
	Guarantors			Non Guarantors			Eliminations		Consolidated
Net cash flows provided by operating activities	$	74,413		$	5,116		$	-	$	79,529
Net cash flows used in investing activities		(151,451	)		(6,482	)		-		(157,933	)
Net cash flows provided by (used in) financing activities		95,721			3,722			-		99,443

Exhibit 99.4 - 24

The Partnership may redeem the senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100 percent of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date. At any time before December 15, 2010, the Partnership may redeem some or all of the notes at a redemption price equal to 100 percent of the principal amount plus a make-whole premium, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change of control, each holder of notes will be entitled to require us to purchase all or a portion of its notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the date of purchase.  The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of the Partnership’s debt agreements, including the Credit Facility. Subsequent to the GE EFS Acquisition, no bond holder has exercised this option.

The senior notes contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain types of transactions with affiliates; and (vi) sell assets or consolidate or merge with or into other companies. If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership and its restricted subsidiaries will no longer be subject to many of the foregoing covenants.

Finance Corp. has no operations and will not have revenue other than as may be incidental co-issuer of the senior notes.  Since the Partnership has no independent operations, the guarantees are full unconditional and joint and several and there are no subsidiaries of the Partnership that do not guarantee the senior notes, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes for periods ending prior to December 31, 2007.

Fourth Amended and Restated Credit Agreement.  At December 31, 2006, RGS’ Fourth Amended and Restated Credit Agreement (“Credit Facility”) allowed for borrowings of $850,000,000 consisting of $600,000,000 in term loans and $250,000,000 in a revolving credit facility.  The availability for letters of credit was $100,000,000.  RGS had the option to increase the commitments under the revolving credit facility or the term loan facility, or both, by an amount up to $200,000,000 in the aggregate, provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase in commitments have been met. On September 28, 2007, the Partnership amended its Credit Facility, increasing the revolving debt commitment to $500,000,000. The Partnership retained its option to increase the commitment under the revolving or term credit facilities by an aggregate amount up to $250,000,000, subject to the same conditions noted above.

RGS’ obligations under the Credit Facility are secured by substantially all of the assets of RGS and its subsidiaries and are guaranteed, except for those owned by one of our subsidiaries, by the Partnership and each such subsidiary.  The revolving loans mature in five years.

Interest on revolving loans thereunder will be calculated, at the option of RGS, at either: (a) a base rate plus an applicable margin of 0.50 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 1.50 percent per annum.  The weighted average interest rates for the revolving and term loan facilities, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 8.78 percent, 7.70 percent, and 6.57 percent for the years ended December 31, 2007, 2006, and 2005.

RGS must pay (i) a commitment fee equal to 0.30 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 1.50 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

The Credit Facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to EBITDA and EBITDA to interest expense within certain threshold ratios. At December 31, 2007, RGS and its subsidiaries were in compliance with these covenants.

The Credit Facility restricts the ability of RGS to pay dividends and distributions other than reimbursements of the Partnership for expenses and payment of dividends to the Partnership to the extent of the Partnership’s determination of available cash (so long as no default or event of default has occurred or is continuing).  The Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, the ability of RGS (but not the Partnership):

·   to incur indebtedness

·   to grant liens;

·   to enter into sale and leaseback transactions;

·   to make certain investments, loans and advances;

·   to dissolve or enter into a merger or consolidation;

·   to enter into asset sales or make acquisitions;

Exhibit 99.4 - 25

·   to enter into transactions with affiliates;

·   to prepay other indebtedness or amend organizational documents or transaction documents (as defined in the Credit Facility);

·   to issue capital stock or create subsidiaries; or

·   to engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Credit Facility or reasonable extensions thereof.

The Partnership treated the amendment of the Credit Facility as an extinguishment and reissuance of debt, and therefore recorded a charge to loss on debt refinancing in the year ended December 31, 2006 of $5,626,000.

In July 2007, the Partnership used a portion of the proceeds from the equity offering to repay the $50,000,000 outstanding principal balance of term loan against the credit facility, together with accrued interest. Unamortized loan origination costs of $503,000 were written off and charged to loss on debt refinancing in the year ended December 31, 2007.

8. Other Assets

Intangible assets, net.  Intangible assets, net consist of the following.

	Permits and Licenses			Customer Contracts			Total
	(in thousands)
Balance at January 1, 2006	$	11,040		$	5,330		$	16,370
Additions		-			63,202			63,202
Amortization		(793	)		(1,856	)		(2,649	)
Balance at December 1, 2006		10,247			66,676			76,923
Additions		-			5,242			5,242
Disposals		(108	)		-			(108	)
Amortization		(771	)		(3,482	)		(4,253	)
Balance at December 31, 2007	$	9,368		$	68,436		$	77,804

The weighted average amortization period for permits and licenses is fifteen years and for customer contracts is twenty four years. The expected amortization of the intangible assets for each of the five succeeding years is as follows.

Year ending December 31,	Total
	(in thousands)
2008	$	3,780
2009		3,780
2010		3,780
2011		3,643
2012		342

Goodwill.  Goodwill consists of the following.

	Gathering and Processing		Transportation		Total
	(in thousands)
Balance at January 1, 2006	$	23,309	$	34,243	$	57,552
Additions		-		-		-
Balance at December 31, 2006		23,309		34,243		57,552
Additions		36,523		-		36,523
Balance at December 31, 2007	$	59,832	$	34,243	$	94,075

Exhibit 99.4 - 26

9. Fair Value of Financial Instruments

The estimated fair value of financial instruments was determined using available market information and valuation methodologies.  The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities.  Restricted cash and related escrow payable approximate fair value due to the relatively short-term settlement period of the escrow payable.  Risk management assets and liabilities are carried at fair value.  Long-term debt other than the senior notes was comprised of borrowings under which, at December 31, 2007 and 2006, accrued interest under a floating interest rate structure.  Accordingly, the carrying value approximates fair value for the long term debt amounts outstanding.  The estimated fair value of the senior notes based on third party market value quotations was $367,778,000 as of December 31, 2007.

10. Leases

The Partnership leases office space and certain equipment for various periods and determined that these leases are operating leases.  The Partnership also sold its 34 mile NGL pipeline located in east Texas for $3,000,000 on June 29, 2007 and simultaneously entered into transportation and operating agreements with the buyer. The Partnership accounted for this transaction as a sale-leaseback, which qualifies for capital lease treatment and the lease term is 20 years. Contingent rentals on this capital lease may be imposed if the Partnership increases the volume of NGLs shipped on the leased pipeline. The minimum lease payments escalate annually by an amount equal to the increase in a consumer price index beginning at mid-year 2010 and continue to escalate through the remainder of the term of the lease. The following table is a schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2007.

For the year ended December 31,	Operating		Capital
	(in thousands)
2008	$	505	$	402
2009		196		401
2010		194		409
2011		160		422
2012		27		436
Thereafter		-		8,010
Total minimum lease payments	$	1,082	$	10,080
Less: Amount representing estimated executory costs (such as maintenance and insurance), including profit thereon, included in minimum lease payments				2,054
Net minimum lease payments				8,026
Less: Amount representing interest				4,981
Present value of net minimum lease payments			$	3,045

The following table sets forth the Partnership’s assets and obligations under the capital lease which are included in other current and long-term liabilities on the balance sheet.

	December 31, 2007
	(in thousands)
Gross amount included in gathering and transmission systems	$	3,000
Less accumulated amortization		(75	)
	$	2,925
Current obligation under capital lease	$	365
Noncurrent obligation under capital lease		2,680
	$	3,045

Total rent expense for operating leases, including those leases with terms of less than one year, was $1,597,000, $1,721,000, and $1,430,000 for the years ended December 31, 2007, 2006, and 2005, respectively.  The Partnership subleases office space from an affiliate.  The lease is classified as an operating lease and provides for minimum annual rentals of $148,000 through September 2010, plus contingent rentals based on a fixed allocation of operating expenses.

Exhibit 99.4 - 27

11. Commitments and Contingencies

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Construction and Operating Agreement.  Prior to the acquisition of FrontStreet by the Partnership, FrontStreet entered into a construction and operation agreement (“C&O Agreement”) contract with a third party.  Under the terms of the C&O Agreement, the third party is responsible for operating, maintaining and repairing the FrontStreet gathering system.  Subject to prior approval, the Partnership is responsible for paying for capital additions and expenses incurred by the operator of the FrontStreet gathering system.  The C&O Agreement shall remain in effect until such time as the gathering agreement (discussed below)  terminates or the third party is removed as operator in accordance with terms of the C&O Agreement.

The C&O Agreement also requires the third party to comply with all applicable environmental standards.  While the Partnership would be responsible for any environmental contamination as a result of the operation, remedies are provided to the Partnership under the C&O Agreement allowing it to recover costs incurred to remediate a contaminated site.  Additionally, the C&O Agreement states that the Partnership is specifically responsible for the removal, remediation, and abatement of Polychlorinated Biphenyls (“Remediation Work”).  However, under the terms of the C&O Agreement, the Partnership can include up to $2,200,000 of expenditures for Remediation Work related to conditions in existence prior to October 1994.  The Partnership has obtained an indemnification against any environmental losses for preexisting conditions prior to the acquisition date from the previous owner.  The Partnership has escrowed $750,000 in the event the third party does not agree to include in the cost of service expenditures for Remediation Work.  As of December 31, 2007, the Partnership has not recorded any obligation for Remediation Work.  The C&O Agreement shall remain in effect until such time as the gathering agreement (discuss below) terminates or the third party is removed as operator in accordance with terms of the C&O Agreement.

Gathering Agreement.  Prior to the acquisition of FrontStreet by the Partnership, FrontStreet has entered into a gathering agreement (“Gathering Agreement”) contract into with a third party, whereby the third party dedicates for gathering by the FrontStreet gathering system all of the commercially producible gas in a defined list of producing fields.  The Gathering Agreement allows the Partnership to charge a per unit gathering fee (the “Gathering Fee”) calculated on estimated cost of service over the total estimated units to be transported in a calendar year.  The Gathering Fee is predetermined for a calendar year by November 7 of the preceding calendar year and then subject to redetermination on June 7.  As part of the redetermination process, the Gathering Fee is trued-up, inclusive of interest, based on actual costs incurred including abandonment costs and actual units transported.  The term of the Gathering Agreement is for as long as gas is capable of being produced in commercial quantities, subject to certain exceptions in the event of an ownership change of the gas field, or the removal of the third party as operator of the FrontStreet gathering system.

Annual Settlement Payment Agreement.  The Partnership and the third are also parties to an annual settlement payment agreement (“ASPA”) which provides the Partnership with a fixed return on its investment in the FrontStreet gathering system.  The ASPA also provides the mechanism for recovery of the costs of current period Remediation Work.  The amount due under the ASPA is calculated monthly, inclusive of interest.  Payments under the ASPA for a calendar year are due on the following March 15.  The term of the ASPA is the same as the Gathering Agreement.

Escrow Payable. At December 31, 2007, $6,029,000 remained in escrow pending the completion by El Paso Field Services, LP (“El Paso”) of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to the assets in north Louisiana and in the mid-continent area. In the El Paso PSA, El Paso indemnified the predecessor of our operating partnership RGS against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and subject to certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities.

Exhibit 99.4 - 28

In January 2008, the Board of Directors of the General Partner and the Partnership has signed a settlement of the El Paso environmental remediation. Under the settlement, El Paso will clean up and obtain “no further action” letters from the relevant state agencies for three owned Partnership facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities at that site. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. The Partnership will release all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced per a specified schedule as El Paso completes its cleanups and the remainder will be released upon completion.

Environmental. A Phase I environmental study was performed on the Waha assets in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties.  The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000.  No governmental agency has required the Partnership to undertake these remediation efforts.  Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote.  Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future.  The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles.  No claims have been made.

TCEQ Notice of Enforcement. On February 15, 2008, the Texas Commission on Environmental Quality, or TCEQ, sent us a notice of enforcement, or NOE, relating to the air emissions at our Tilden processing plant. The NOE relates to 15 alleged violations occurring during the period from March 2006 through July 2007 of the emissions event reporting and recordkeeping requirements of the TCEQs rules. Specifically, it is alleged that one of our subsidiaries failed to report, using the TCEQ’s electronic data base for emissions events, 15 emissions events within 24 hours of the incident, as required. These events occurred during times of failure of the Tilden plant sulphur recovery unit or ancillary equipment and resulted in the flaring of acid gas.  Of these events, one relates to an alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide and three related to more than 2,500 and less than 40,000 pounds of sulphur dioxide (including two releases of 126 and 393 pounds of hydrogen sulphide). In 2007, the subsidiary completed construction of an acid gas reinjection unit at the Tilden plant and permanently shut down the Sulphur Recovery Unit.

All these emission incidents were reported by means of fax or telephone to the TCEQ pursuant to an informal procedure established with the TCEQ by the prior owner of the Tilden plant and, indeed, the subsidiary paid the emission fines in connection with all the incidents.  Using that procedure, all except one were timely. The TCEQ has, prior to our subsidiary acquiring the Tilden facility, established its electronic data base for emissions events, but the subsidiary did not report using that electronic facility. It is the failure to report each incident timely using the electronic reporting procedure that is the subject of the NOE. Representatives of the Partnership are scheduled to meet with the staff of the TCEQ in the near future regarding the NOE. Management of the General Partner does not expect the NOE to have a material adverse effect on its results of operations or financial condition.

12. Related Party Transactions

The Partnership paid management and financial advisory fees in the amount of $1,073,000 were paid to an affiliate of HM Capital Partners in the year ended December 31, 2005. Concurrent with the closing of the Partnership’s IPO, the Partnership paid $9,000,000 to an affiliate of HM Capital Partners to terminate a management services contract with a remaining tenor of nine years. TexStar paid $361,000 and $13,000 to HM Capital Partners for the years ended December 31, 2006 and 2005 in relation to a management services contract.  In connection with the TexStar Acquisition, the Partnership paid $3,542,000 to terminate TexStar’s management services contract.

Under an omnibus agreement, Regency Acquisition LP, the entity that formerly owned the General Partner, agreed to indemnify the Partnership in an aggregate not to exceed $8,600,000, generally for three years after February 3, 2006, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to the Partnership and occurring or existing before that date.  To date, no claims have been made against the omnibus agreement.

Exhibit 99.4 - 29

BlackBrush Oil & Gas, LP (“BBOG”), an affiliate of HM Capital Partners, is a natural gas producer on the Partnership’s gas gathering and processing system.  At the time of the TexStar Acquisition, BBOG entered into an agreement providing for the long term dedication of the production from its leases to the Partnership. In July 2007, BBOG sold its interest in the largest of these leases to an unrelated third party. BlackBrush Energy, Inc., a wholly owned subsidiary of HM Capital Partners, is the lessee of office space in the south Texas region. The Partnership subleased space from BlackBrush Energy, Inc., for which it paid $151,000, $70,000, and $13,000 in 2007, 2006, and 2005, respectively. The Partnership acquired compressors from BBOG for $1,800,000 on January 31, 2005. The purchase price exceeded the book value by $1,152,000. Since BBOG and the Partnership were commonly controlled entities, the net book value was recorded as the acquisition price. All of the Partnership’s related party receivables, payables, revenues and expenses as disclosed in the consolidated financial statements relate to BBOG.

In July 2005, in connection with the amendment and restatement of the credit agreement, Regency Acquisition LP contributed an additional $15,000,000 of equity. In February 2005, TexStar issued a promissory note to HM Capital Partners in the amount of $600,000 bearing interest at a fixed rate of 8.5 percent per annum.  Concurrent with TexStar Acquisition, the promissory note was repaid in full. TexStar paid a transaction fee in the amount of $1,200,000 to an affiliate of HM Capital Partners upon completing its acquisition of the Como Assets.  This amount was capitalized as a part of the purchase price.

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, our General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $27,628,000 and $16,789,000 were recorded in the Partnership’s financial statements during the years ended December 31, 2007 and 2006 as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership on common and subordinated units, together with the general partner interest, HM Capital Partners and affiliates received cash distributions of $24,392,000 and $20,139,000 during the years ended December 31, 2007 and 2006 as a result of their ownership in the Partnership. In conjunction with distributions by the Partnership on common and subordinated units, together with the general partner interest, GE EFS and affiliates received cash distributions of $14,592,000 during the year ended December 31, 2007, as a result of their ownership in the Partnership.

GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $7,735,000 to maintain the General Partner’s two percent interest in the Partnership.

As a part of the GE EFS Acquisition, affiliates of HM Capital Partners entered into an agreement to hold 4,692,417 of the Partnership’s common units for a period of 180 days. In addition, a separate affiliate of HM Capital Partners entered into an agreement to hold 3,406,099 of the Partnership’s common units for a period of one year.

Concurrent with the GE EFS acquisition, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units for a total consideration of $24.00 per unit. Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

Exhibit 99.4 - 30

13. Concentration Risk

The following table provides information about the extent of reliance on major customers and gas suppliers.  Total revenues and cost of gas and liquids from transactions with single external customer or supplier amounting to 10 percent or more of revenues or cost of gas and liquids are disclosed below, together with the identity of the reporting segment.

		Year Ended
Customer / Supplier	Reporting Segement	December 31, 2007		December 31, 2006		December 31, 2005
		(in thousands)
Customer A	Transportation	$	*	$	89,736	$	132,539
Customer B	Gathering and Processing		*		*		76,115
Supplier A	Transportation	$	*	$	*	$	93,188
Supplier B	Transportation		157,046		*		63,398
Supplier C	Transportation		*		*		75,414
Supplier D	Gathering and Processing		*		67,751		*
*Amounts are less than 10 percent of the total revenues or cost of gas and liquids

The Partnership is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations.  These agreements are customary and the terms follow standard industry practice.  In the opinion of management, these agreements reduce the overall counterparty risk exposure.

14. Segment Information

As of December 31, 2007, the Partnership has two reportable segments: i) gathering and processing and ii) transportation. Gathering and processing involves the collection of hydrocarbons from producer wells across the five operating regions and transportation of them to a plant where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment.

The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with larger pipelines or trading hubs and other markets.  The Partnership performs transportation services for shipping customers under firm or interruptible arrangements.  In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations.  The Partnership also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets.  The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create the intersegment revenues shown in the table below.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses.  Segment margin is defined as total revenues, including service fees, less cost of gas and liquids.  Management believes segment margin is an important measure because it is directly related to volumes and commodity price changes.  Operation and maintenance expenses are a separate measure used by management to evaluate operating performance of field operations.  Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses.  These expenses are largely independent of the volume throughput but fluctuate depending on the activities performed during a specific period.  The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

Exhibit 99.4 - 31

Results for each statement of operations period, together with amounts related to balance sheets for each segment, are shown below.

	Gathering and Processing		Transportation		Corporate		Eliminations			Total
	(in thousands)
External Revenue
Year ending December 31, 2007	$	812,861	$	377,377	$	-	$	-		$	1,190,238
Year ending December 31, 2006		645,770		251,095		-		-			896,865
Year ending December 31, 2005		505,721		203,680		-		-			709,401
Intersegment Revenue
Year ending December 31, 2007		-		101,734		-		(101,734	)		-
Year ending December 31, 2006		-		39,504		-		(39,504	)		-
Year ending December 31, 2005		-		57,066		-		(57,066	)		-
Cost of Gas and Liquids
Year ending December 31, 2007		658,100		318,045		-		-			976,145
Year ending December 31, 2006		534,398		206,048		-		-			740,446
Year ending December 31, 2005		444,857		188,008		-		-			632,865
Segment Margin
Year ending December 31, 2007		154,761		59,332		-		-			214,093
Year ending December 31, 2006		111,372		45,047		-		-			156,419
Year ending December 31, 2005		60,864		15,672		-		-			76,536
Operation and Maintenance
Year ending December 31, 2007		53,496		4,504		-		-			58,000
Year ending December 31, 2006		35,008		4,488		-		-			39,496
Year ending December 31, 2005		22,362		1,929		-		-			24,291
Depreciation and Amortization
Year ending December 31, 2007		40,309		13,545		1,220		-			55,074
Year ending December 31, 2006		26,831		11,927		896		-			39,654
Year ending December 31, 2005		17,955		4,666		550		-			23,171
Assets
December 31, 2007		886,477		329,862		62,071		-			1,278,410
December 31, 2006		648,116		316,038		48,931		-			1,013,085
Investments in Unconsolidated Subsidiaries
December 31, 2007		-		-		-		-			-
December 31, 2006		5,616		-		-		-			5,616
Goodwill
December 31, 2007		59,832		34,243		-		-			94,075
December 31, 2006		23,309		34,243		-		-			57,552
Expenditures for Long-Lived Assets
Year ending December 31, 2007		112,813		16,555		416		-			129,784
Year ending December 31, 2006		192,115		29,810		1,725		-			223,650
Year ending December 31, 2005		140,463		158,079		923		-			299,465

The table below provides a reconciliation of total segment margin to net loss from continuing operations.

	Year Ended
	December 31, 2007			December 31, 2006			December 31, 2005
				(in thousands)
Net loss from continuing operations	$	(13,836	)	$	(7,244	)	$	(11,592	)
Add (deduct):
Operation and maintenance		58,000			39,496			24,291
General and administrative		39,713			22,826			15,039
Loss on assets sales		1,522			-			-
Management services termination fee		-			12,542			-
Transaction expenses		420			2,041			-
Depreciation and amortization		55,074			39,654			23,171
Interest expense, net		52,016			37,182			17,880
Loss on debt refinancing		21,200			10,761			8,480
Other income and deductions, net		(1,252	)		(839	)		(733	)
Income tax expense		931			-			-
Minority interest in net income from subsidairy		305			-			-
Total segment margin	$	214,093		$	156,419		$	76,536

Exhibit 99.4 - 32

15. Equity-Based Compensation

The Partnership’s long-term incentive plan (“LTIP”) for the Partnership’s employees, directors and consultants covering an aggregate of 2,865,584 common units. Awards under the LTIP have been made since completion of the Partnership’s IPO.  All outstanding, unvested LTIP awards at the time of the GE EFS Acquisition vested upon the change of control. As a result, the Partnership recorded a one-time charge of $11,928,000 during the year ended December 31, 2007 in general and administrative expenses. LTIP awards made subsequent to the GE EFS Acquisition vest on the basis of one-fourth of the award each year. Options expire ten years after the grant date. LTIP compensation expense of $15,534,000 and $2,906,000 is recorded in general and administrative in the statement of operations for the years ended December 31, 2007 and 2006, respectively.

The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. The Partnership used the simplified method outlined in Staff Accounting Bulletin No. 107 for estimating the exercise behavior of option grantees, given the absence of historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its units have been publicly traded. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with common units on a net basis.  The following assumptions apply to the options granted during the periods presented.

	Year Ended
	December 31, 2007			December 31, 2006
Weighted average expected life (years)		4			4
Weighted average expected dividend per unit	$	1.51		$	1.40
Weighted average grant date fair value of options	$	2.31		$	1.32
Weighted average risk free rate		4.6	%		4.25	%
Weighted average expected volatility		16.0	%		15.0	%
Weighted average expected forfeiture rate		11.0	%		5.0	%

The common unit options activity for the years ending December 31, 2007 and 2006 is as follows.

2007
			Weighted		Weighted		Aggregate
			Average		Average		Intrinsic
			Exercise		Contractual		Value *
Common Unit Options			Price		Term (Years)		(in thousands)
Outstanding at beginning of period	909,600		$	21.06
Granted	21,500			27.18
Exercised	(149,934	)		21.78			$	1,738
Forfeited or expired	(42,498	)		21.85
Outstanding at end of period	738,668			21.05		8.2		9,104
Exercisable at end of period	738,668			21.05				9,104
2006
			Weighted		Weighted		Aggregate
			Average		Average		Intrinsic
			Exercise		Contractual		Value *
Common Unit Options			Price		Term (Years)		(in thousands)
Outstanding at beginning of period	-		$	-
Granted	943,900			21.05
Exercised	-			-
Forfeited or expired	(34,300	)		20.75
Outstanding at end of period	909,600			21.06		9.3	$	5,522
Exercisable at end of period	-			-		-		-
* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding.

Exhibit 99.4 - 33

The Partnership will make distributions to non-vested restricted common units at the same rate as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time; non-vested restricted units are subject to forfeitures on termination of employment. The Partnership expects to recognize $11,793,000 of compensation expense related to the grants under LTIP ratably over the future vesting period.

The restricted (non-vested) common unit activity for the years ending December 31, 2007 and 2006 is as follows.

2007
Restricted (Non-Vested) Common Units			Weighted Average Grant Date Fair Value
Outstanding at beginning of period	516,500		$	21.06
Granted	615,500			30.44
Vested	(684,167	)		22.91
Forfeited or expired	(50,333	)		27.20
Outstanding at end of period	397,500		$	31.62
2006
Restricted (Non-Vested) Common Units			Weighted Average Grant Date Fair Value
Outstanding at beginning of period	-			-
Granted	516,500		$	21.06
Forfeited or expired	-			-
Outstanding at end of period	516,500		$	21.06

16. Subsequent Events

Acquisition of CDM Resource Management, Ltd. On January 15, 2008, the Partnership and an indirect wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an agreement and plan of merger (the “Merger Agreement”) with CDM Resource Management, Ltd., CDM OLP GP,LLC and CDMR Holdings, LLC (each a “CDM Partner” and together the “CDM Partners”).  Upon closing, CDM merged with and into Merger Sub, with Merger Sub continuing as the surviving entity after the merger (the “CDM Merger”).  Following the merger, Merger Sub changed its name to CDM Resource Management LLC. CDM provides its customers with turn-key natural gas contract compression services to maximize their natural gas and crude oil production, throughput, and cash flow in Texas, Louisiana, and Arkansas. The Partnership operates and manages CDM as a separate reportable segment.

Exhibit 99.4 - 34

The total purchase price, subject to customary post-closing adjustments, paid by the Partnership for the partnership interests of CDM consisted of (1) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000, (2) the payment of an aggregate of $161,945,000 in cash to the CDM Partners, and (3) the payment of $316,500,000 of CDM’s debt obligations. Of the Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement. Such common units constitute security to the Partnership for a period of one year after the closing of the CDM Merger with respect to any obligations of the CDM Partners under the Merger Agreement, including obligations for breaches of representation, warranties and covenants. In connection with the CDM Merger, the General Partner entered into Amendment No. 4 to the Amended and Restated Agreement of Limited Partnership of the Partnership, which created the Partnership’s Class D common units.  The Class D common units have the same terms and conditions as the Partnership’s common units, except that the Class D common units are not entitled to participate in distributions of operating surplus by the Partnership. The Class D common units automatically convert into common units on a one-for-one basis on the close of business on the first business day after the record date for the quarterly distribution on the common units for the quarter ending December 31, 2008.  The Class D common units were issued in a private offering conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 afforded by Section 4(2) thereof.

General Partner Capital Contribution. In January 2008, the General Partner made a capital contribution of $7,663,000 to maintain its two percent interest in the Partnership in respect of the FrontStreet Acquisition and the CDM acquisition.

Amendments of the Fourth Amended and Restated Credit Agreement.RGS entered into Amendment No. 4 to its Fourth Amended and Restated Credit Facility (the “4th Amendment”) on January 15, 2008, thereby expanding its revolving credit facility thereunder to $750,000,000, and borrowed $476,000,000 in revolving loans thereunder.  Such borrowings, together with cash on hand, were used for the following purposes: (i) $291,000,000 to repay the balance outstanding under CDM’s bank credit facility, (ii) $25,500,000 to fund the purchase of compressors and other equipment held by CDM under capital leases, and (iii) $161,945,000 to fund the cash portion of the consideration issued to the CDM Partners in the CDM Merger.  The 4th Amendment did not materially change the terms of the RGS revolving credit facility.

RGS entered into Amendment No. 5 to its Fourth Amended and Restated Credit Facility (the “5th Amendment”) on February 13, 2008, thereby expanding its revolving credit facility thereunder to $900,000,000. The availability for letters of credit is $100,000,000. The Partnership has the option to request an additional $250,000,000 in revolving commitments with 10 business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the fourth amended and restated credit agreement, or the credit facility, have been met. The 5th Amendment did not materially change the terms of the RGS revolving credit facility.

Cash Distributions. On February 14, 2008, the Partnership paid a distribution of $0.40 per common and subordinated unit.

Acquisition of Nexus.  On March 25, 2008, the Partnership acquired Nexus Gas Holdings, LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”) by merger for $87,749,000 in cash, including customary closing adjustments.  Nexus Gas Partners LLC, the sole member of Nexus prior to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustment.  The Partnership funded the Nexus Acquisition through borrowings under the existing revolving credit facility.

Upon consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Southern Natural Gas Company (“Sonat”).  Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat Asset Acquisition”) that would enable the Nexus gathering system to be integrated into the Partnership’s north Louisiana asset base.  The Sonat Asset Acquisition is subject to abandonment approval and jurisdictional redetermination by the FERC, as well as customary closing conditions.  Upon closing of the Sonat Asset Acquisition, the Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, the Partnership will make an additional payment of $25,000,000 to the Nexus Member.

Exhibit 99.4 - 35

Interest Rate Swaps.  On February 29, 2008, the Partnership entered into two year interest rate swaps related to $300,000,000 of borrowings under our revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin.  These interest rate swaps were designated as cash flow hedges on March 7, 2008 and the Partnership incurred an immaterial mark-to-market charge.

Commodity Swaps.  On March 7, 2008, the Partnership entered offsetting trades against its existing 2009 portfolio of hedges, which it believes will substantially reduce the volatility of its net income.  This group of trades, along with the pre-existing 2009 portfolio, will continue to be accounted for on a mark-to-market basis.  Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow hedges.  As a result, the Partnership increased the hedged percentage to 75 percent.

17. Quarterly Financial Data (Unaudited)

Quarter Ended	Operating Revenues		Operating Income (Loss)		Net Income (Loss)			Basic and Diluted Earnings per Common and Subordinated Unit (1)			Basic and Diluted Earnings per Class B Common Unit (1)			Basic and Diluted Earnings per Class C Common Unit (1)		Basic and Diluted Earnings per Class E Common Unit
	(in thousands except earning per unit)
2007
March 31	$	256,428	$	13,480	$	(1,295	)	$	(0.06	)	$	-		$	0.48	$	-
June 30		302,828		8,768		(7,263	)		(0.16	)		-			-		0.07
September 30		295,825		21,545		(9,833	)		(0.23	)		-			-		0.63
December 31		335,157		15,571		4,555			0.03			-			-		0.53
2006
March 31		231,266		1,500		(6,319	)		(0.18	)		(0.18	)		-		-
June 30		214,658		11,948		3,760			0.08			0.08			-		-
September 30		229,132		11,987		(11,272	)		(0.28	)		(0.14	)		0.11		-
December 31		221,809		14,425		6,587			0.08			-			1.15		-

(1) The following table depicts the change to the quarterly earnings (loss) per unit data for each class of common units as compared to previously disclosed amounts in the respective quarterly filings. The quarterly amounts have been corrected for an error made in the calculation of loss per unit resulting from the issuance of Class C common units at a discount as further discussed in the loss per unit note.

	Three Months Ended
	September 30, 2006			December 31, 2006			March 31, 2007
Common and subordinated unit	$	(0.01	)	$	(0.09	)	$	(0.03	)
Class B common unit		-			-			-
Class C common unit		0.11			1.15			0.48

Exhibit 99.4 - 36

EX-99.5

Exhibit 99.5.  Ratio of Earnings to Fixed Charges

Regency Energy Partners LP

Ratio of Earnings to Fixed Charges

(in thousands, except for ratio amounts)

(Unaudited)

		Regency Energy Partners LP												Regency LLC Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005			Period from Acquisition  December 1, 2004) to December 31, 2004				Period from January 1, 2004 to November 30, 2004		Period from Inception (April 2, 2003) to December 31, 2003
Earnings:
Income (loss) from continuing operations	$	(12,600	)	$	(7,244	)	$	(11,592)		$	1,474		$	20,137	$	6,174
Add:
Interest expense		52,016			37,182			17,880			1,335			5,097		2,392
Portion of rent under long-term operating leases representative of an interest factor		477			574			477			43			468		190
Amortization of capitalized interest		186			131			-			-			-		-
Distributed income from investees accounted for under equity method		-			-			-			-			280		-
Less:
Equity income		(43	)		(532	)		(312	)		(56	)		-		-
Total earnings available for fixed charges	$	40,036		$	30,111		$	6,453		$	2,796		$	25,982	$	8,756
Fixed Charges:
Interest expense	$	52,016		$	37,182		$	17,880		$	1,335		$	5,097	$	2,392
Portion of rent under long-term operating leases representative of an interest factor		477			574			477			43			468		190
Capitalized interest		1,754			511			2,613			-			-		-
Total fixed charges	$	54,247		$	38,267		$	20,970		$	1,378		$	5,565	$	2,582
Ratio of earnings to fixed charges (x times) (1)		-			-			-			2.03			4.67		3.39
(1) Earnings were insufficient to cover fixed charges by:	$	14,211		$	8,156		$	14,517		$	-		$	-	$	-

EX-99.6

Exhibit 99.6.  Consent of KPMG LLP

Consent of Independent Registered Public Accounting Firm

The Partners

Regency Energy Partners LP:

We consent to the incorporation by reference in the registration statement No. 333-140088 on Form S-8, registration statement No. 333-141809 on Form S-3, and registration statement No. 333-141764 on Form S-4 of Regency Energy Partners LP of our report dated May 9, 2008, with respect to the consolidated balance sheet of Regency Energy Partners LP as of December 31, 2007, and the related consolidated statements of operations, comprehensive loss, cash flows, and partners’ capital for the year then ended, which report appears herein this Form 8-K of Regency Energy Partners LP.

/s/ KPMG LLP

Dallas, Texas

May 9, 2008

EX-99.7

Exhibit 99.7.  Consent of Deloitte & Touche LLP

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-140088 on Form S-8, Registration Statement No. 333-141809 on Form S-3, and Registration Statement No. 333-141764 on Form S-4 of our report dated March 29, 2007 (February 28, 2008 as to Note 4)  relating to the consolidated financial statements of Regency Energy Partners LP (the “Partnership”) (which report expresses an unqualified opinion and includes an explanatory paragraph related to the Partnership’s acquisition of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC as acquisitions of entities under common control in a manner similar to a pooling of interests) appearing in this Annual Report on Form 10-K of Regency Energy Partners LP for the year ended December 31, 2007.

/s/ Deloitte and Touche LLP

Dallas, Texas

May 9, 2008