10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number: 000-51757

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	16-1731691
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2001 Bryan Street Suite 3700, Dallas, Texas	75201
(Address of principal executive offices)	(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report): None

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units of Limited Partner Interests	The Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer, accelerated filer and small reporting company” in Rule 12b-2 of the Exchange Act.    x  Large accelerated filer    ¨  Accelerated filer ¨  Non-accelerated filer (Do not check if a smaller reporting company)    ¨  Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨    No  x

As of June 30, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,209,264,971 based on the closing sale price as reported on the NASDAQ Global Select Market.

There were 81,197,103 common units outstanding as of February 18, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

None

REGENCY ENERGY PARTNERS LP

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2008

TABLE OF CONTENTS

		PAGE
	Introductory Statement
	Cautionary Statement about Forward-Looking Statements
Item 1	Business	1
Item 1A	Risk Factors	18
Item 1B	Unresolved Staff Comments	37
Item 2	Properties	37
Item 3	Legal Proceedings	37
Item 4	Submission of Matters to a Vote of Security Holders	37
Item 5	Market of Registrant’s Common Equity, Related Unitholders Matters and Issuer Purchases of Equity Securities	38
Item 6	Selected Financial Data	40
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 7A	Quantitative and Qualitative Disclosure about Market Risk	68
Item 8	Financial Statements and Supplementary Data	70
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A	Controls and Procedures	70
Item 9B	Other Information	72
Item 10	Directors, Executive Officers and Corporate Governance	73
Item 11	Executive Compensation	79
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	96
Item 13	Certain Relationships and Related Transactions, and Director Independence	98
Item 14	Principal Accounting Fees and Services	99
Item 15	Exhibit and Financial Statement Schedules	100

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, 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 annual report on Form 10-K:

Name	Definition or Description
Alinda	Alinda Capital Partners LLC, a Delaware limited liability company that is an independent private investment firm specializing in infrastructure investments
Alinda Investor I	Alinda Gas Pipeline I, L.P., a Delaware limited partnership
Alinda Investor II	Alinda Gas Pipeline II, L.P., a Delaware limited partnership
Alinda Investors	Alinda Investor I and Alinda Investor II, collectively
ASC	ASC Hugoton LLC, an affiliate of GECC
Bbls/d	Barrels per day
BBE	BlackBrush Energy, Inc., a wholly owned subsidiary of HM Capital Partners
BBOG	BlackBrush Oil & Gas, LP, an affiliate of HM Capital Partners
Bcf	One billion cubic feet
Bcf/d	One billion cubic feet per day
BTU	A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM	CDM Resource Management LLC
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CFTC	Commodity Futures Trading Commission
DHS	Department of Homeland Security
DOT	U.S. Department of Transportation
EIA	Energy Information Administration
EITF	Emerging Issues Task Force
EnergyOne	FrontStreet EnergyOne LLC
El Paso	El Paso Field Services, LP
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
Finance Corp	Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
FrontStreet	FrontStreet Hugoton LLC
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 Regency GP LP, which effectively manages the business and affairs of the Partnership
GSTC	Gulf States Transmission Corporation
HLPSA	Hazardous Liquid Pipeline Safety Act
HM Capital Partners	HM Capital Partners LLC
HMTF Gas Partners	HMTF Gas Partners II, L.P.
ICA	Interstate Commerce Act
IPO	Initial public offering of securities
IRS	Internal Revenue Service
Lehman	Lehman Brothers Holdings, Inc.
LIBOR	London Interbank Offered Rate

Name	Definition or Description
MLP	Master limited partnership
LTIP	Long-Term Incentive Plan
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

Nexus	Nexus Gas Holdings, LLC
NOE	Notice of enforcement
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 Global Select Market
NYMEX	New York Mercantile Exchange
OSHA	Occupational Safety and Health Act
Partnership	Regency Energy Partners LP
PHMSA	Pipeline and Hazardous Materials Safety Administration
Pueblo	Pueblo Midstream Gas Corporation
Pueblo Holdings	Pueblo Holdings, Inc.
RCRA	Resource Conservation and Recovery Act
RGS	Regency Gas Services LLC
Regency HIG	Regency Haynesville Intrastate Gas LLC
SCADA	System Control and Data Acquisition
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standard
Sonat	Southern Natural Gas Company
TCEQ	Texas Commission on Environmental Quality
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

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we can not give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions, including without limitation the following:

• declines in the credit markets and the availability of credit for us as well as for producers connected to our system and our customers;

• the level of creditworthiness of, and performance by, our counterparties and customers;

• our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;

• our use of derivative financial instruments to hedge commodity and interest rate risks;

• the amount of collateral required to be posted from time to time in our transactions;

• changes in commodity prices, interest rates, demand for our services;

• changes in laws and regulations impacting the midstream sector of the natural gas industry;

• weather and other natural phenomena;

• industry changes including the impact of consolidations and changes in competition;

• our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and

• the effect of accounting pronouncements issued periodically by accounting standard setting boards.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of this annual report.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Part I

Item 1. Business

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 and Oklahoma. We were formed in 2005. All of our midstream assets are located in historically well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

We divide our operations into three business segments:

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

• Transportation: We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Gas (“RIGS”) pipeline system; and

• Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 778,000 horsepower of compression for third party producers in Texas, Louisiana, and Arkansas. In addition, our contract compression segment operates approximately 196,000 horsepower of compression for our gathering and processing and transportation segments.

RECENT DEVELOPMENTS

On February 26, 2009 the Partnership, GECC and the Alinda Investors entered into a definitive agreement to form a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas from the Haynesville Shale, one of the fastest growing natural gas plays in the United States. In connection with the joint venture, we will contribute all of our ownership interests in RIGS, valued at $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. GECC and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.

We will serve as the operator of the joint venture, and will provide all employees and services for the operation and management of the joint venture’s assets. We expect to close the joint venture transaction as promptly as practicable following the satisfaction of the closing conditions, but no later than April 30, 2009.

INDUSTRY OVERVIEW

General. The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-user markets. It consists of natural gas gathering, compression, dehydration, processing and treating, fractionation, marketing and transportation. Raw natural gas produced from the wellhead is gathered and often delivered to a plant located near the production, where it is treated, dehydrated, and/or processed. Natural gas processing involves the separation of raw natural gas into pipeline quality natural gas, principally methane, and mixed NGLs. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by interstate and intrastate pipelines to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to fractionators, which separates the NGLs into their components, such as ethane, propane, butane, isobutane and natural gasoline. The NGL components are then sold to end users.

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The following diagram depicts our role in the process of gathering, processing, compression, marketing and transporting natural gas.

Overview of U.S. market. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas wells. Natural gas remains a critical component of energy consumption in the United States. According to the EIA, total annual domestic consumption of natural gas is expected to increase from 21.6 Tcf in 2006 to 23.8 Tcf in 2016, representing an average annual growth rate of 1.0 percent, with a slight decrease in consumption through the year 2030. During the year ended December 31, 2006, the United States consumed 21.6 Tcf, down from 22.4 in 2005. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

Short-Term Energy Outlook. A recent report issued by the EIA projects a 1.3 percent decline in natural gas consumption in 2009 due to current economic conditions. In 2010, the report projects a 0.6 percent increase in consumption, depending on the timing and pace of economic recovery. Drilling activities in 2009 are expected to decline as a result of the sluggish demand for natural gas and lower commodity prices. Despite the decrease in drilling activities, production in 2009 from the lower forty-eight states is expected to increase by 1.1 percent due to the increase in gas supply from increased drilling activities in 2008, followed by a decrease of 1.1 percent in 2010.

Gathering. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collects natural gas from points near producing wells and transports it to larger diameter pipelines for further transportation. We own and operate large gathering systems in five geographic regions of the United States.

Compression. Gathering systems are operated at design pressures that seek to maximize the total through-put volumes from all connected wells. Natural gas compression is a mechanical process in which a volume of gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production against a higher pressure that exists in the connected gathering system. Field compression is typically used to lower the entry pressure, while maintaining or increasing the exit pressure of a gathering system to allow it to operate at a lower receipt pressure and provide sufficient pressure to deliver gas into a higher pressure downstream pipeline.

Amine Treating. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb these impurities from the gas. After mixing, the gas and amine are separated, and the impurities are removed from the amine by heating. The treating plants are sized by the amine circulation capacity in terms of gallons per minute. We own and operate natural gas processing and/or treating plants in three geographic regions: east, south and west Texas.

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Processing. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream. The principal component of natural gas is methane, but most natural gas also contains varying amounts of heavier hydrocarbon components, or NGLs. Natural gas is described as lean or rich depending on its content of NGLs. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use because it contains NGLs and impurities. Removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. We own and operate natural gas processing plants in four geographic regions, north Louisiana, the mid-continent and east and west Texas.

Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient in synthetic rubber) and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We do not own or operate any NGL fractionation facilities.

Marketing. Natural gas marketing involves the sale of the pipeline-quality natural gas either produced by processing plants or purchased from gathering systems or other pipelines. We perform a limited natural gas marketing function for our account and for the accounts of our customers.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines.

GATHERING AND PROCESSING OPERATIONS

General. We operate significant gathering and processing assets in five geographic regions of the United States: north Louisiana, the mid-continent, and east, south, and west Texas. We contract with producers to gather raw natural gas from individual wells or central delivery points, which may have multiple wells behind them, located near our processing plants or gathering systems. Following the execution of a contract, we connect wells and central delivery points to our gathering lines through which the raw natural gas flows to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At our processing plants, we remove any impurities in the raw natural gas stream and extract the NGLs.

All raw natural gas flowing through our gathering and processing facilities is supplied under gathering and processing contracts having terms ranging from month-to-month to the life of the oil and gas lease. For a description of our contracts, please read “—Our Contracts” and “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Operations.”

The pipeline-quality natural gas remaining after separation of NGLs through processing is either returned to the producer or sold, for our own account or for the account of the producer, at the tailgates of our processing plants for delivery to interstate or intrastate gas transportation pipelines.

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The following table sets forth information regarding our gathering systems and processing plants as of December 31, 2008.

Region	Pipeline Length (Miles)	Plants	Compression (Horsepower)	Through-put Volume Capacity (MMcf/d)
North Louisiana	680	5	43,931	910
East Texas	371	1	14,597	215
South Texas	623	2	30,081	555
West Texas	806	1	46,134	355
Mid-Continent	3,470	1	48,931	437
Total	5,950	10	183,674	2,472

The following map depicts the geographic areas of our operations.

North Louisiana Region. Our north Louisiana region includes:

• two cryogenic natural gas processing plants;

• a large integrated natural gas gathering and processing system located primarily in five parishes (Claiborne, Union, Lincoln, DeSoto and Ouachita) of north Louisiana;

• a gathering system in Shelby County, Texas and Desoto Parish, Louisiana; and

• a refrigeration plant located in Bossier Parish, and a conditioning plant in Webster Parish.

Through this gathering and processing system and its interconnections with our RIGS pipeline system in north Louisiana described in “—Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, marketing and transportation.

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The north Louisiana gathering system consists of 600 miles of natural gas gathering pipelines ranging in size from two inches to 10 inches in diameter. The system gathers raw natural gas from producers and delivers most of it to processing plants. The remainder of the raw natural gas is lean natural gas, which does not require processing and is delivered directly to interstate pipelines and RIGS.

A gathering system in Desoto Parish and Shelby County, Texas was acquired by the Partnership through its purchase of Nexus on March 25, 2008. This gathering system consists of 80 miles of natural gas gathering pipeline ranging in diameter from four to fourteen inches and is located in the Joaquin, Logansport, Spider and Benson Fields, which have experienced significant drilling activity. The system gathers lean natural gas from producers for delivery directly to interstate and intrastate pipelines.

East Texas Region. Our east Texas assets gather, compress, process and dehydrate natural gas through a large integrated natural gas gathering and processing system located in Rains, Wood, Van Zandt, Henderson, Franklin, and Hopkins counties that delivers natural gas to the Eustace processing plant that is equipped with a sulfur removal unit. Natural gas produced in this region contains high levels of hydrogen sulfide.

The natural gas supply for our east Texas gathering systems is derived primarily from natural gas wells located in a mature basin that generally have long lives and predictable gas flow rates.

Our east Texas processing plant is a cryogenic natural gas processing plant that was constructed in its current location in 1981. It includes an amine treating unit, a cryogenic NGL recovery unit, a nitrogen rejection unit, and a liquid sulfur recovery unit. This plant removes hydrogen sulfide, carbon dioxide and nitrogen from the natural gas stream, recovers NGLs and condensate, delivers pipeline quality gas at the plant outlet and produces sulfur.

South Texas Region. Our south Texas assets gather, compress, and dehydrate natural gas in LaSalle, Webb, Karnes, Atascosa, McMullen, Frio, and Dimmitt counties. Some of the natural gas produced in this region can have significant hydrogen sulfide and carbon dioxide content and some of this gas is processed by third parties. These systems are connected to processing and treating facilities that include an acid gas reinjection well.

The natural gas supply for our south Texas gathering systems is derived primarily from natural gas wells located in a mature basin that generally have long lives and predictable gas flow rates.

One of our treating plants consists of inlet compression, a 60 MMcf/d amine treating unit, a 55 MMcf/d amine treating unit and a 40 ton (per day) liquid sulfur recovery unit. An additional 55 MMcf/d amine treating unit is currently inactive. This plant removes hydrogen sulfide from the natural gas stream, which in this region often contains a high concentration of hydrogen sulfide and carbon dioxide, recovers condensate, delivers pipeline quality gas at the plant outlet and reinjects acid gas.

A second treating plant in Atascosa County includes a 500 gpm amine treater, pipeline interconnect facilities, and approximately 13 miles of ten inch diameter pipeline. We operate this plant with a joint venture partner that operates a lean gas gathering system in the Edwards Lime natural gas trend.

West Texas Region. Our gathering system offers wellhead-to-market services in Ward, Winkler, Reeves, and Pecos counties which surround the Waha Hub, one of Texas’ major natural gas market areas. As a result of the proximity of this system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. Natural gas exploration and production drilling in this area has primarily targeted productive zones in the Permian Delaware basin and Devonian basin. These basins are mature basins with wells that generally have long lives and predictable flow rates.

We offer producers four different levels of natural gas compression on the Waha gathering system, as compared to the two levels typically offered in the industry. By offering multiple levels of compression, our gathering system is often more cost-effective for our producers, since the producer is typically not required to pay for a level of compression that is higher than the level they require.

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The Waha processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Waha gathering system. This plant was constructed in 1965, and, due to recent upgrades to state of the art cryogenic processing capabilities, it is a highly efficient natural gas processing plant. The Waha processing plant also includes an amine treating facility which removes carbon dioxide and hydrogen sulfide from raw natural gas gathered in our Waha gathering system before moving the natural gas to the processing plant. The acid gas is reinjected.

Mid-Continent Region. Our mid-continent region includes natural gas gathering systems located primarily in Kansas and Oklahoma. Our mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas from approximately 1,500 wells. These systems are geographically concentrated, with each central facility located within 90 miles of the others. We operate our mid-continent gathering systems at low pressures to increase the total through-put volumes from the connected wells. Wellhead pressures are therefore adequate to access the gathering lines without the cost of wellhead compression.

Our mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, including the Hugoton Basin in southwest Kansas and the Anadarko Basin in western Oklahoma. These mature basins have continued to provide generally long-lived, predictable reserves.

TRANSPORTATION OPERATIONS

Regency Intrastate Gas Pipeline System. We own and operate a 320-mile intrastate natural gas pipeline system, known as RIGS, in north Louisiana extending from Caddo parish to Franklin parish. This system, with pipeline ranging from 12 to 30 inches in diameter, includes total system capacity of 910 MMcf/d, 26,370 horsepower of compression. Natural gas generally flows from west to east on the pipeline from wellhead connections or connections with other gathering systems. RIGS transports natural gas produced from the Elm Grove field, the Vernon field, and the Sligo field, which are three of the five largest natural gas producing fields in Louisiana.

In connection with the joint venture arrangement that we recently entered into with GECC and the Alinda Investors, we will contribute all of our ownership interests in RIGS to the joint venture.

Gulf States Transmission. Our interstate pipeline, owned and operated by GSTC, consists of 10 miles of 12 and 20 inch diameter pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. The pipeline has a FERC certificated capacity of 150 MMcf/d.

CONTRACT COMPRESSION OPERATIONS

The natural gas contract compression segment services include designing, sourcing, owning, insuring, installing, operating, servicing, repairing, and maintaining compressors and related equipment for which we guarantee our customers 98 percent mechanical availability for land installations and 96 percent mechanical availability for over-water installations. We focus on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering, natural gas lift for crude oil production and natural gas processing. We believe that we improve the stability of our cash flow by focusing on field-wide compression applications because such applications generally involve long-term installations of multiple large horsepower compression units. Our contract compression operations are primarily located in Texas, Louisiana, and Arkansas.

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The following tables set forth certain information regarding contract compression’s revenue generating horsepower as of December 31, 2008 and 2007.

	December 31, 2008
Horsepower Range	Revenue Generating Horsepower	Percentage of Revenue Generating Horsepower		Number of Units
0-499	59,288	7	%	351
500-999	83,299	11	%	134
1,000+	636,080	82	%	425
	778,667	100	%	910
	December 31, 2007
Horsepower Range	Revenue Generating Horsepower	Percentage of Revenue Generating Horsepower		Number of Units
0-499	41,958	7	%	252
500-999	61,609	11	%	99
1,000+	464,660	82	%	307
	568,227	100	%	658

OUR CONTRACTS

The table below provides the margin by product and percentage for the years ended December 31, 2008 and 2007.

Margin by Product	2008		2007
Net Fee	64	%	43	%
NGL	18		37
Gas	10		10
Condensate	5		8
Helium and Sulfur	3		2
Total	100	%	100	%

Gathering and Processing Contracts. We contract with producers to gather raw natural gas from individual wells or central receipt points located near our gathering systems and processing plants. Following the execution of a contract with the producer, we connect the producer’s wells or central receipt points to our gathering lines through which the natural gas is delivered to a processing plant owned and operated by us or a third party. We obtain supplies of raw natural gas for our gathering and processing facilities under contracts having terms ranging from month-to-month to life of the lease. We categorize our processing contracts in increasing order of commodity price risk as fee-based, percentage-of-proceeds, or keep-whole contracts. For a description of our fee-based arrangements, percent-of-proceeds arrangements, and keep-whole arrangements, please read “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Operations.” During the year ended December 31, 2008, purchases in our gathering and processing segment from one producer represented 17.3 percent of the cost of gas and liquids on our consolidated statement of operations.

Transportation Contracts.

Fee Transportation Contracts. We provide natural gas transportation services on RIGS pursuant to contracts with natural gas shippers. These contracts are all fee-based. Generally, our transportation services are of two types: firm transportation and interruptible transportation. When we agree to provide firm transportation service,

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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 the capacity is utilized by the shipper, and in some cases the shipper also pays a commodity charge with respect to quantities actually shipped. When we agree to provide interruptible transportation service, we become obligated to transport natural gas nominated and actually delivered by the shipper only to the extent that we have available capacity. The shipper pays no reservation charge for this service but pays a commodity charge for quantities actually shipped. We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with the FERC with respect to transportation authorized under Section 311 of the NGPA.

Merchant Transportation Contracts. We perform a limited merchant function on RIGS. We purchase natural gas from producers or gas marketers at receipt points on our system at a price adjusted to reflect our transportation fee and transport that gas to delivery points on our system where we sell the natural gas at market price. We regard the margin with respect to those purchases and sales as the economic equivalent of a fee for our transportation service. During the year ended December 31, 2008, purchases in our transportation segment from one producer represented 5.3 percent of the cost of gas and liquids on our consolidated statement of operations. In the aggregate, 22.6 percent of the cost of gas and liquids in our gathering & processing and transportation segments were purchased from this producer.

These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the same index price on the date of settlement.

Compression Contracts. We generally enter into a new contract with respect to each distinct application for which we will provide contract compression services. Our compression contracts typically have an initial term between one and five years, after which the contract continues on a month-to-month basis. Our customers generally pay a fixed monthly fee, or, in rare cases, a fee based on the volume of natural gas actually compressed. We are not responsible for acts of force majeure and our customers are generally required to pay our monthly fee for fixed fee contracts, or a minimum fee for throughput contracts, even during periods of limited or disrupted production. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessary lubricants, although certain fees and expenses are the responsibility of the customer under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity. We are also reimbursed by our customers for certain ancillary expenses such as trucking, crane and installation labor costs, depending on the terms agreed to in a particular contract.

COMPETITION

Gathering and Processing. We face strong competition in each region in acquiring new gas supplies. Our competitors in acquiring new gas supplies and in processing new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer.

Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors for gathering and related services in each region include:

• North Louisiana: CenterPoint Energy Field Services and DCP Midstream’s PanEnergy Louisiana Intrastate, LLC (Pelico);

• East Texas: Enbridge Energy Partners LP and Eagle Rock Energy Partners, L.P.;

• South Texas: Enterprise Products Partners LP and DCP Midstream Partners, L.P;

• West Texas: Southern Union Gas Services and Enterprise Products Partners LP; and

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• Mid-Continent: DCP Midstream Partners, L.P., ONEOK Energy Marketing and Trading, L.P., and Penn Virginia Corporation.

Transportation. Competition in natural gas transportation is characterized by price of transportation, the nature of the markets accessible from a transportation pipeline and the type of service provided. In transporting natural gas across north Louisiana, we typically receive gas from gathering facilities and deliver gas to intrastate and interstate markets. We compete with interstate and intrastate pipelines that have access to the same gathering facilities or production areas. Our major competitors in the natural gas transportation business are DCP Midstream Partners, L.P., CenterPoint Energy Transmission, Gulf South Pipeline, L.P. and Texas Gas Transmission, LLC.

Contract Compression. The natural gas contract compression services business is highly competitive. We face competition from large national and multinational companies with greater financial resources and, on a regional basis, from numerous smaller companies. Our main competitors in the natural gas contract compression business, based on horsepower, are Exterran Holdings, Inc., Compressor Systems, Inc., USA Compression, and J-W Operating Company.

We believe that the superior mechanical availability of our standardized compressor fleet is the primary basis on which we compete and a significant distinguishing factor from our competition. All of our competitors attempt to compete on the basis of price. We believe our pricing has proven competitive because of the superior mechanical availability we deliver, the quality of our compression units, as well as the technical expertise we provide to our customers. We believe our focus on addressing customers’ more complex natural gas compression needs related primarily to field-wide compression applications differentiates us from many of our competitors who target smaller horsepower projects related to individual wellhead applications.

RISK MANAGEMENT

To manage commodity price risk, we have implemented a risk management program under which we seek to:

• match sales prices of commodities, including natural gas, NGLs, condensate, sulfur, and helium, with purchases under our contracts;

• manage our portfolio of contracts to reduce commodity price risk;

• optimize our portfolio by active monitoring of basis, swing, and fractionation spread exposure; and

• hedge a portion of our exposure to commodity prices.

As a consequence of our gathering and processing contract portfolio, we derive a portion of our earnings from a long position in NGLs, natural gas and condensate, resulting from the purchase of natural gas for our account or from the payment of processing charges in kind. This long position is exposed to commodity price fluctuations in both the NGL and natural gas markets. Operationally, we mitigate this price risk by generally purchasing natural gas and NGLs at prices derived from published indices, rather than at a contractually fixed price and by marketing natural gas and natural gas liquids under similar pricing mechanisms. In addition, we optimize the operations of our processing facilities on a daily basis, for example by rejecting ethane in processing when recovery of ethane as an NGL is uneconomical. We also hedge this commodity price risk by entering a series of swap contracts for individual NGLs, natural gas, and WTI crude oil. Our hedging position and needs to supplement or modify our position are closely monitored by the Risk Management Committee of the Board of Directors. Please read “Item 7A-Quantitative and Qualitative Disclosures About Market Risk” for information regarding the status of these contracts. As a matter of policy we do not acquire forward contracts or derivative products for the purpose of speculating on price changes.

Our contract compression business does not have direct exposure to natural gas commodity price risk because we do not take title to the natural gas we compress and because the natural gas we use as fuel for our

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compressors is supplied by our customers without cost to us. Our indirect exposure to short-term volatility in natural gas and crude oil commodity prices is mitigated because natural gas and crude oil production, rather than exploration, is the primary demand driver for our contract compression services, and because our focus on field-wide applications reduces our dependence on individual well economics.

REGULATION

Industry Regulation

Intrastate Natural Gas Pipeline Regulation. RIGS is an intrastate pipeline regulated by the Louisiana Department of Natural Resources, Office of Conservation (DNR). The DNR is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Louisiana also has agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers. RIGS transports interstate natural gas in Louisiana for many of its shippers pursuant to Section 311 of the NGPA. To the extent that RIGS transports natural gas in interstate service, its rates, terms and conditions of service are subject to the jurisdiction of the FERC. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of such fair and equitable rates are subject to refund with interest. NGPA Section 311 rates deemed fair and equitable by the FERC are generally analogous to the cost-based rates that the FERC deems “just and reasonable” for interstate pipelines under the NGA.

On September 23, 2008, the FERC issued a Letter Order approving the continuation of RIGS’ maximum rates for Section 311 transportation services as follows: Firm Service—reservation fee of $4.5625 per MMBtu monthly ($0.15 MMBtu daily) and commodity fee of $0.05 per MMBtu; Interruptible Service—transportation fee of $0.20 per MMBtu; and Fuel Retention—up to two percent of receipts. The FERC Letter order was the result of a settlement, which also permits RIGS’ maximum fuel retention rate to increase to two percent when new compression is added to the RIGS system. As part of the settlement RIGS also agreed to re-justify or establish new rates for its Section 311 services by May 1, 2011. The triennial rate review requirement is a standard settlement provision in most intrastate pipeline proceedings for Section 311 service.

FERC has adopted new regulations requiring certain major non-interstate pipelines to post, on a daily basis, receipt and delivery point capacities and scheduled flow information. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. Although these regulations are currently subject to rehearing before the FERC and to petitions for review before the United States Court of Appeals for the District of Columbia Circuit, the posting requirements impose increased costs and administrative burdens on intrastate pipelines. The FERC has also issued a Notice of inquiry seeking comments related to transactional reporting requirements of intrastate pipelines providing NGPA Section 311 transportation services. The Notice of Inquiry specifically seeks comments regarding competitive impacts of having different reporting requirements for interstate pipelines and intrastate pipelines performing Section 311 services and the market transparency benefits of requiring Section 311 intrastate pipelines to comply with the same reporting requirements of interstate pipelines. It is possible that FERC may propose new regulations as a result of the Notice of Inquiry and that such rules could add to RIGS’ regulatory burden and costs.

Interstate Natural Gas Pipeline Regulation. The FERC also has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the pipeline owned by our subsidiary, GSTC. Under the NGA, rates charged for interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates are subject to refund with interest. GSTC holds a FERC-approved tariff setting forth cost-based rates, terms and conditions for services to shippers wishing to take interstate transportation service. The FERC’s authority extends to:

• rates and charges for natural gas transportation and related services;

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• certification and construction of new facilities;

• extension or abandonment of services and facilities;

• maintenance of accounts and records;

• relationships between the pipeline and its energy affiliates;

• terms and conditions of service;

• depreciation and amortization policies;

• accounting rules for ratemaking purposes;

• acquisition and disposition of facilities;

• initiation and discontinuation of services;

• prevention of market manipulation in connection with interstate sales, purchases, or transportation of natural gas; and

• information posting requirements.

Any failure on our part to comply with the laws and regulations governing interstate transmission service could result in the imposition of administrative, civil and criminal penalties.

FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. We do not believe that we will be affected by any such FERC action in a manner materially differently than any other natural gas companies with whom we compete.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of substantial, on-going litigation, so the classification and regulation of one or more of our gathering systems may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and, in other instances, complaint-based rate regulation. We are subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers that purchase gas to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Natural gas gathering may receive greater regulatory scrutiny at the state level now that the FERC has allowed a number of interstate pipeline transmission companies to transfer formerly jurisdictional assets to gathering companies. For example, in 2006, the TRRC approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines that prohibit such entities from unduly discriminating in favor of their affiliates.

In addition, many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and

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services. Our gathering operations also may be subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters may be considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of NGL and Crude Oil Transportation. We have a pipeline in Louisiana that transports NGLs in interstate commerce pursuant to a FERC-approved tariff. Under the ICA, the Energy Policy Act of 1992, and rules and orders promulgated thereunder, the FERC regulates the tariff rates for interstate NGL transportation and imposes reporting and a number of other requirements. Our NGL transportation tariff is required to be just and reasonable and not unduly discriminatory or confer any undue preference. FERC has established an indexing system for transportation rates for oil, NGLs and other products that allows for an annual inflation-based increase in the cost of transporting these liquids to the shipper. The implementation of these regulations has not had a material adverse effect on our results of operations. Any failure on our part to comply with the laws and regulations governing interstate transmission of NGLs could result in the imposition of administrative, civil and criminal penalties. We also have a Texas common carrier pipeline that provides intrastate transportation of crude oil subject to a local tariff approved by and on file with the TRRC. This pipeline is subject to a number of TRRC regulatory requirements governing rates and terms and conditions of service.

Sales of Natural Gas and NGLs. Our ability to sell gas in interstate markets is subject to FERC authority and its oversight. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to state or federal regulation. However, with regard to our physical purchases and sales of these energy commodities, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or the CFTC.

The prices at which we sell natural gas are affected by many competitive factors, including the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC has also imposed new rules requiring whole-sale purchasers and sellers of natural gas to report certain aggregated annual volume and other information beginning in 2009.

We also have firm and interruptible transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, we are subject to FERC requirements related to use of the interstate capacity. Any failure on our part to comply with the FERC’s regulations or an interstate pipeline’s tariff could result in the imposition of administrative civil and criminal penalties.

Sales of Liquids. Sales of crude oil, natural gas, condensate and NGLs are not currently regulated. Prices of these products are set by the market rather than by regulation.

Anti-Market Manipulation Requirements. Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, NGLs and crude oil, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1,000,000 per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

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Anti-Terrorism Regulations. We may be subject to future anti-terrorism requirements of the DHS. The DHS has issued its National Infrastructure Protection Plan calling for broadened efforts to “reduce vulnerability, deter threats, and minimize the consequences of attacks and other incidents” as they relate to pipelines, processing facilities and other infrastructure. The precise parameters of DHS regulations and any related sector-specific requirements are not currently known, and there can be no guarantee that any final anti-terrorism rules that might be applicable to our facilities will not impose costs and administrative burdens on our operations.

Environmental Matters

General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations, 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 cost 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. We cannot be certain, however, that identification of presently unidentified conditions, more rigorous 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.

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. On February 3, 2009, the omnibus agreement expired, with no claims having been filed.

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 prevent, minimize or remediate 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

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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. 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. 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. It is possible 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 El Paso. Under the agreement pursuant to which our operating partnership acquired assets from El Paso Field Services LP and its affiliates in 2003, an escrow account of $9,000,000 relating to claims, including environmental claims, was established. After the time of this agreement, a Final Site Investigation Report was prepared. Based on this additional investigation, environmental issues were determined to exist with respect to a number of our facilities.

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

West Texas Assets. A Phase I environmental study was performed on certain assets located in west Texas 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

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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 against the Partnership with respect to environmental issues at the west Texas assets or under the policy.

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 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 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. 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.

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.

Climate Change. In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. These cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and, on an annual basis, surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas) we process.

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s

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holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas we gather and process.

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.

The DOT has recently proposed new regulations as directed by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The proposed rules require operators of hazardous liquids pipelines, gas pipelines and LNG facilities with at least one control room to develop, implement and submit written control room management procedures and to conduct baseline point by point verifications and periodic testing of a pipeline’s SCADA system. When adopted, the new regulations may increase regulatory burdens and administrative costs for the Partnership.

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TCEQ Notice of Enforcement. On February 15, 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”). The NOE alleges that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. On April 3, 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000, and it later reduced its settlement demand to $360,000 in July 2008. The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has referred the matter to its litigation division for further administrative proceedings.

EMPLOYEES

As of December 31, 2008, our General Partner employs 784 employees, of whom 560 are field operating employees and 224 are mid-and senior-level management and staff. None of these employees are represented by a labor union and there are no outstanding collective bargaining agreements to which our General Partner is a party. Our General Partner believes that it has good relations with its employees.

AVAILABLE INFORMATION

We file annual and quarterly financial reports, current-event reports as well as interim updates of a material nature to investors with the Securities and Exchange Commission. You may read and copy any of these materials at the SEC’s Public Reference Room at 100 F. Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of that site is http://www.sec.gov.

We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through its Internet website located at http://www.regencygasservices.com. Our annual reports are filed on Form 10-K, our quarterly reports are filed on Form 10-Q, and current-event reports are filed on Form 8-K; we also file amendments to reports filed or furnished pursuant to Section 13(a) or Section 15(d) of the Exchange Act. References to our website addressed in this report are provided as a convenience and do not constitute, or should be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.

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Item 1A. Risk Factors

RISKS RELATED TO OUR BUSINESS

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

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

• prevailing economic conditions;

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

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

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

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

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

• our debt service requirements;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets;

• restrictions contained in our debt agreements;

• the level of capital expenditures we make;

• the cost of acquisitions, if any; and

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

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

We may have difficulty financing our planned capital expenditures, which could adversely affect our results and growth.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of

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obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, because of the recent downturn in the financial markets, including the issues surrounding the solvency of many institutional lenders and the recent failure of several banks, our ability to obtain capital from our credit facility may be impaired. For example, as a result of Lehman Brothers Holding, Inc., or Lehman, filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a subsidiary of Lehman that is a committed lender under our credit facility has declined requests to honor its commitment to lend under our credit facility. As of February 20, 2009, the unfunded commitment from Lehman is $5,578,000, thereby effectively reducing the amount available to us under our credit facility to $894,422,000. Upon the repayment of all of our existing outstanding borrowings, the amount available to us under our credit facility will be effectively reduced to $880,000,000. We may be unable to utilize the full borrowing capacity under our credit facility if other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that Lehman’s subsidiary has refused to fund or if any of the remaining committed lenders is unable or unwilling to fund their respective portion of any funding request we make under our credit facility.

Our leverage may limit our ability to borrow additional funds, make distributions, comply with the terms of our indebtedness or capitalize on business opportunities.

Our leverage is significant in relation to our partners’ capital. Our debt to capital ratio, calculated as total debt divided by the sum of total debt and partners’ capital, as of December 31, 2008 was 50.9 percent. We will be prohibited from making cash distributions during an event of default under any of our indebtedness, and, in the case of the indenture under which our senior notes were issued, the failure to maintain a prescribed ratio of consolidated cash flows (as defined in the indenture) to interest expense. Various limitations in our credit facility, as well as the indenture for our senior notes, may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, in order to make acquisitions, to reduce debt, or for other purposes.

The interest rate on our senior notes is fixed and the loans outstanding under our credit facility bear interest at a floating rate. Interest rates on future credit facilities and debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price for our units will be affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and our ability to issue additional equity in order to make acquisitions, to reduce debt or for other purposes.

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Natural gas, NGLs and other commodity prices are volatile, and an unfavorable change in these prices could adversely affect our cash flow and operating results.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGLs prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. Recently, oil and natural gas prices have been extremely volatile and have declined substantially. On February 17, 2009, the price of oil on the New York Mercantile Exchange fell to $34.97 per barrel for March 2009 delivery from a high of $147.27 per barrel in July 2008. Volatility in oil and natural gas prices can impact our customers’ activity levels and spending for our products and services, as well as our margins under our keep-whole and percentage-of proceeds natural gas gathering and processing contracts.

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

• the level of domestic oil and natural gas production;

• the availability of imported oil and natural gas;

• actions taken by foreign oil and gas producing nations;

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

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

• the availability and marketing of competitive fuels;

• the impact of energy conservation efforts; and

• the extent of governmental regulation and taxation.

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

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

Our gathering and processing and transportation pipeline systems are dependent on the level of production from natural gas wells that supply our systems and from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase through-put volume levels on our gathering and transportation pipeline systems and the asset utilization rates at

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our natural gas processing plants, we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets are: the level of successful drilling activity near our systems and our ability to compete with other gathering and processing companies for volumes from successful new wells.

The level of natural gas drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and processing facilities and pipeline transportation systems, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budget limitations which have become more constrained in recent months, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if additional natural gas reserves were discovered in areas served by our assets, producers may choose not to develop those reserves. If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, through-put volumes on our pipelines and the utilization rates of our processing facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition.

Our natural gas contract compression operations significantly depend upon the continued demand for and production of natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, demand for energy, and availability of alternative energy sources. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of production activity and result in a decline in the demand for our contract compression services and products. Lower natural gas prices or crude oil prices over the long-term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our natural gas contract compression services. Additionally, production from natural gas sources such as longer-lived tight sands, shales and coalbeds constitute an increasing percentage of our compression services business. Such sources are generally less economically feasible to produce in lower natural gas price environments, and a reduction in demand for natural gas or natural gas lift for crude oil may cause such sources of natural gas to be uneconomic to drill and produce, which could in turn negatively impact the demand for our services.

Many of our customers’ drilling activity levels and spending for transportation on our pipeline system may be impacted by the current deterioration in commodity prices and the credit markets.

Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our customers’ equity values have substantially declined. The combination of a reduction of cash flow resulting from recent declines in natural gas prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline system. For example, a number of our customers have announced reduced drilling capital expenditure budgets for 2009. A significant reduction in drilling activity could have a material adverse effect on our operations.

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

We rely on a limited number of producers and other customers for a significant portion of our natural gas supplies and our contracts for compression services. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, we will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. We may be unable to obtain new or renewed contracts on favorable terms,

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if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, and financial condition.

The completion of the joint venture with GECC and the Alinda Investors is subject numerous closing conditions and we may therefore not be able to successfully complete the joint venture.

Consummation of the joint venture transaction with GECC and the Alinda Investors is conditioned on receipt of certain third-party consents and certain other customary closing conditions. If such conditions are not satisfied and the joint venture is not consummated, we would not be able to fund the Haynesville Expansion Project. Credit markets have deteriorated and we believe that alternative financing for the Haynesville Expansion Project is not available on terms that are satisfactory to us. The curtailment of our Haynesville Expansion Project could have a material adverse effect on our results and on our future operations.

If the joint venture is completed, we may be required to make additional capital contributions to the joint venture.

If the joint venture is completed, its management committee may request that we, as 38 percent owners, make additional capital contributions to support its capital expenditure programs. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations. In the event that we elect not to participate in future capital contributions, our ownership interest in the joint venture will be diluted.

If the joint venture is completed, we will own a 38 percent equity interest and will not be able to exercise control over the joint venture.

If the joint venture is completed, we will own a 38 percent ownership interest in the joint venture and GECC will own 12 percent. The joint venture will be managed by a management committee consisting of four members. Each investor will be entitled to appoint one member to the management committee and each member will have a vote equal to the sharing ratio of the partner that appointed such member. Accordingly, we will not be able to exercise control over the joint venture. In addition, the joint venture’s partnership agreement contains standard supermajority voting provisions and also requires that the following actions, among other things, be approved by at least 75 percent of the members of the management committee: merger or consolidation of the joint venture, sale of all or substantially all of the assets of the joint venture, determination to raise additional capital, determining the amount of available cash, causing the joint venture to terminate the master services agreement, approval of any budget and entry into material contracts.

Our contract compression segment depends on particular suppliers and is vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on two vendors, Spitzer Corp. and Standard Equipment Corp., to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships. In addition, since we expect any increase in component prices for compression equipment or packaging costs will be passed on to us, a significant increase in their pricing could have a negative impact on our results of operations.

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

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

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

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

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

In performing our functions in the Gathering and Processing segment, we are a seller of natural gas and NGLs and are exposed to commodity price risk associated with downward movements in commodity prices. As a result of the volatility of commodity prices, we have executed swap contracts settled against ethane, propane, normal butane, iso-butane, natural gas, natural gasoline and west Texas intermediate crude market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. Also, we may seek to limit our exposure to changes in interest rates by using financial derivative instruments and other hedging mechanisms from time to time. For more information about our risk management activities, please read “Item 7A—Quantitative and Qualitative Disclosures about Market Risk.”

Even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect, or our hedging policies and procedures are not followed or do not work as planned.

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

A principal focus of our strategy is to continue to grow by expanding our business both internally and through acquisitions. Our ability to grow internally will depend on a number of factors, some of which will be beyond our control. We may not be able to finance the construction or modifications on satisfactory terms. For example, we have agreed to reimburse the joint venture for the first $20,000,000 of cost overruns relating to the Haynesville Expansion Project. In addition, if the Haynesville Expansion Project is not completed at the

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budgeted cost, we may be required to make an additional capital contribution, which we may not be able to fund out of our operating cash flows and we may not be able to obtain financing on terms that are satisfactory to us. In general, the construction of additions or modifications to our existing systems, and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control. Any project that we undertake may not be completed on schedule, at budgeted cost or at all. Construction may occur over an extended period, and we are not likely to receive a material increase in revenues related to such project until it is completed. Moreover, our revenues may not increase immediately upon the completion of construction because the anticipated growth in gas production that the project was intended to capture does not materialize, our estimates of the growth in production prove inaccurate or for other reasons. For example, producers in the area may decrease their activity levels in the area near our Haynesville Expansion Project due to the current deterioration in the credit markets or the recent declines in the price for natural gas. To the extent producers in the area are unable to execute their expected drilling programs, the return on our investment from this project may not be as attractive as we anticipate. For any of these reasons, newly constructed or modified midstream facilities may not generate our expected investment return and that, in turn, could adversely affect our cash flows and results of operations. In addition, our ability to undertake to grow in this fashion will depend on our ability to hire, train, and retain qualified personnel to manage and operate these facilities when completed.

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

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

We may be unable to integrate successfully the operations of future acquisitions with our operations and we may not realize all the anticipated benefits of the past and any future acquisitions.

Integration of acquisitions with our business and operations is a complex, time consuming, and costly process. Failure to integrate acquisitions successfully with our business and operations in a timely manner may have a material adverse effect on our business, financial condition, and results of operations. We cannot assure you that we will achieve the desired profitability from past or future acquisitions. In addition, failure to assimilate future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions involve numerous risks, including:

• operating a significantly larger combined organization and adding operations;

• difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;

• the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

• the loss of significant producers or markets or key employees from the acquired businesses;

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

• the failure to realize expected profitability, growth or synergies and cost savings;

• properly assessing and managing environmental compliance;

• coordinating geographically disparate organizations, systems, and facilities; and

• coordinating or consolidating corporate and administrative functions.

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Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

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

We compete with similar enterprises in each of our areas of operations. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas than we do. In addition, our customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using ours. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services that we provide to our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors.

The natural gas contract compression business is highly competitive, and there are low barriers to entry for individual projects. In addition, some of our competitors are large national and multinational companies that have greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer or more powerful compressor fleets that would create additional competition for us. In addition, our customers that are significant producers of natural gas and crude oil may purchase and operate their own compressor fleets in lieu of using our natural gas contract compression services.

All of these competitive pressures could have a material adverse effect on our business, results of operations, and financial condition.

If third-party pipelines interconnected to our processing plants become unavailable to transport NGLs, our cash flow and results of operations could be adversely affected.

We depend upon third party pipelines that provide delivery options to and from our processing plants for the benefit of our customers. If any of these pipelines become unavailable to transport the NGLs produced at our related processing plants, we would be required to find alternative means to transport the NGLs from our processing plants, which could increase our costs, reduce the revenues we might obtain from the sale of NGLs, or reduce our ability to process natural gas at these plants.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

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

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

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

• inadvertent damage from construction and farm equipment;

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

• fires and explosions;

• weather related hazards, such as hurricanes and extensive rains which could delay the construction of assets and extreme cold which can cause freezing of pipelines, limiting throughput; and

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

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

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

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

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and certain gathering lines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

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We currently estimate that we will incur costs of $1,622,000 in 2009 to implement pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

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

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

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

Our interstate gas transportation operations, including Section 311 service performed by our intrastate pipelines, are subject to FERC regulation; failure to comply with applicable regulation, future changes in regulations or policies, or the establishment of more onerous terms and conditions applicable to interstate or Section 311 natural gas transportation service could adversely affect our business.

FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the pipeline owned by our subsidiary, GSTC. Under the NGA, rates charged for interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates are subject to refund with interest. GSTC holds a FERC-approved tariff setting forth cost-based rates, terms and conditions for services to shippers wishing to take interstate transportation service. In addition, FERC regulates the rates, terms and conditions of service with respect to Section 311 transportation service provided by RIGS. The FERC also has policies and rules regarding the shipment of gas on interstate pipelines. Any failure on our part to comply with applicable FERC-administered statutes, rules, regulations and orders could result in the imposition of administrative, civil and/or criminal penalties, or both. In addition, FERC has authority to alter its rules, regulations and policies to comply with its statutory authority. We cannot give any assurance regarding the likely future regulations under which RIGS or GSTC will operate its interstate transportation business or the effect such regulation could have on our business, results of operations, or ability to make distributions.

As a limited partnership entity, we may be disadvantaged in calculating its cost-of-service for rate-making purposes.

Under current policy applied under the NGA, FERC permits interstate gas pipelines to include, in the cost-of-service used as the basis for calculating the pipeline’s regulated rates, a tax allowance reflecting the actual or potential income tax liability on public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In connection with its future Section 311 rate case, RIGS may be required to demonstrate the extent to which inclusion of an income tax allowance in Regency’s cost-of-service is permitted under the current income tax allowance policy. FERC policy also currently allows the inclusion of master limited partnerships in proxy groups used to calculate the appropriate returns on equity under FERC’s discounted cash flow analysis, but FERC limits recognition of certain MLP earnings and allows case-by-case determination by FERC of the appropriateness of any MLP proposed as a member of the pipeline’s proxy group. Although FERC’s

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policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, application of the policy in individual rate cases still entails rate risk due to the case-by-case review requirement. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. Moreover, we cannot guarantee that this policy will not be altered in the future.

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

Our natural gas gathering and intrastate transportation operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices, including, for example, its policies on open access transportation, ratemaking, capacity release. Market promotion indirectly affects intrastate markets, to the extent that RIGS provides interstate natural gas transmission service because its rates and terms and conditions of services are regulated by FERC pursuant to the NGPA. In recent years, FERC has pursued pro-competitive regulatory policies. However, with the passage of the Energy Policy Act of 2005, FERC has expanded its oversight of natural gas purchasers, natural gas sellers, gatherers, intrastate pipelines and shippers on FERC regulated pipelines by imposing new market monitoring and market transparency rules. In addition, FERC recently issued a notice of inquiry seeking comments regarding disparate reporting requirements between intrastate pipelines providing Section 311 services and interstate pipelines. We cannot predict the outcome of FERC’s notice of inquiry proceeding or how FERC will approach future matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated interstate transmission service, on one hand, and intrastate transmission or federally unregulated gathering services, on the other hand, is the subject of regular litigation at FERC and in the courts and of policy discussions at FERC. In such circumstances, the classification and regulation of some of our gathering or our intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. Such a change could result in increased regulation by FERC, which could adversely affect our business.

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

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

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations 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. Certain environmental statutes, including CERCLA and comparable state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released.

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There is inherent risk of the incurrence of environmental costs and liabilities in our business due to the necessity of handling natural gas and NGLs, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. We cannot be certain 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.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, President Obama has expressed support for and Congress is considering legislation to reduce emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Also, the United States Supreme Court’s holding in the 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. It is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, but any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the natural gas we gather and process.

We may not have the ability to raise funds necessary to finance any change of control offer required under our senior notes.

If a change of control (as defined in the indenture) occurs, we will be required to offer to purchase our outstanding senior notes at 101 percent of their principal amount plus accrued and unpaid interest. If a purchase offer obligation arises under the indenture governing the senior notes, a change of control could also have occurred under the senior secured credit facilities, which could result in the acceleration of the indebtedness outstanding thereunder. Any of our future debt agreements may contain similar restrictions and provisions. If a purchase offer were required under the indenture for our debt, we may not have sufficient funds to pay the purchase price of all debt that we are required to purchase or repay.

Our ability to manage and grow our business effectively may be adversely affected if our General Partner loses key management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, the General Partner’s employees operate our business. Our General Partner’s ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions continue to be positive.

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When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if our General Partner is unable to successfully hire, train and retain these important personnel.

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

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

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

RISKS RELATED TO OUR STRUCTURE

GE EFS controls our general partner, which has sole responsibility for conducting our business and managing our operations.

Although our General Partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to its owner, GE EFS. Conflicts of interest may arise between GE EFS, including our General Partner, on the one hand, and us, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires GE EFS or affiliates of GECC to pursue a business strategy that favors us;

• our General Partner is allowed to take into account the interests of parties other than us, such as GE EFS, in resolving conflicts of interest;

• our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and repayments of debt, issuance of additional partnership securities, and cash reserves, each of which can affect the amount of cash available for distribution;

• our General Partner determines which costs incurred are reimbursable by us;

• our partnership agreement does not restrict our General Partner from causing us to pay for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our General Partner intends to limit its liability regarding our contractual and other obligations; and

• our General Partner controls the enforcement of obligations owed to us by our General Partner.

GE EFS and affiliates of GECC may compete directly with us.

GE EFS and affiliates of GECC are not prohibited from owning assets or engaging in businesses that compete directly or independently with us. GE EFS and affiliates of GECC currently own various midstream

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assets and conduct midstream businesses that may potentially compete with us. In addition, GE EFS and affiliates of GECC may acquire, construct or dispose of any additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct or dispose of those assets.

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

Prior to making any distribution on the common units, we will reimburse our General Partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our General Partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. The reimbursement of expenses incurred by our General Partner and its affiliates could adversely affect our ability to pay cash distributions to our unit holders.

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

Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

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

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

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

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

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

Any unitholder is bound by the provisions in the partnership agreement, including the provisions discussed above.

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our General Partner or its Board of Directors and have no right to elect our General

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Partner or its Board of Directors on an annual or other continuing basis. The Board of Directors of our General Partner is chosen by the members of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

The unitholders are currently unable to remove the General Partner without its consent because the General Partner and its affiliates own sufficient units to be able to prevent its removal. A vote of the holders of at least 66 ²/3 percent of all outstanding units voting together as a single class is required to remove the General Partner. As of February 18, 2009 our General Partner owns 30.4 percent of the total of our common units.

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

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of our General Partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of our management.

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

Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their ownership in our General Partner to a third party. The new partners of our General Partner would then be in a position to replace the Board of Directors and officers of our General Partner with their own choices and to control the decisions taken by the Board of Directors and officers.

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

Our General Partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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

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

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

• the market price of the common units may decline.

Certain of our investors may sell units in the public market, which could reduce the market price of our outstanding common units.

Pursuant to agreements with investors in private placements or acquisitions, we have filed registration statements on Form S-3 registering sales by selling unitholders of an aggregate of 19,902,262 of our common units. The registered remaining unsold common units pursuant to these registration statements are 12,802,262. If

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investors holding these units were to dispose of a substantial portion of these units in the public market, whether in a single transaction or series of transactions, it could temporarily reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

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

If at any time our General Partner and its affiliates own more than 80 percent of the common units, our General Partner will have the right, but not the obligation (which it may assign to any of its affiliates or to us) to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of February 18, 2009 our General Partner owns 30.4 percent of the total of our common units.

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

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

• a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• your right to act with other unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.

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

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

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TAX RISKS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states or local entities. If the IRS treats us as a corporation or we become subject to a material amount of entity-level taxation for state or local tax purposes, it would substantially reduce the amount of cash available for payment for distributions on our common units.

Under Section 7704 of the Internal Revenue Code, a publicly traded partnership will be taxed as a corporation unless it satisfies the “qualifying income” exception that allows it to be treated as a partnership for U.S. federal income tax purposes. We believe that we meet the “qualifying income” exception and currently expect to meet such exception for the foreseeable future. If the IRS were to disagree and if we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state and local income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of the units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, legislation has recently been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to us as proposed, it could be reintroduced in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax. Imposition of such a tax on us by Texas, and, if applicable, by any other state, will reduce our cash available for distribution to you.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be reduced to reflect the impact of that law on us.

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

We did not request a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

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

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

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

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax deductions available to you. It also could affect the timing of these tax deductions or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, if the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

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

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

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

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50 percent threshold has been reached, multiple sales of the same unit will be counted only once. Although a termination likely will cause our unitholders to realize an increased amount of taxable income as a percentage of the cash distributed to them, we anticipate that the ratio of taxable income to distributions for future years will return to levels commensurate with our prior tax periods. However, any future termination of our partnership could have similar consequences. Additionally, in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. The position that there was a partnership termination does not affect our classification as a partnership for federal income tax purposes; however, we are treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to prevail that a termination occurred.

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

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in Texas, Oklahoma, Kansas, Louisiana, West Virginia and Arkansas. Each of these states, other than Texas, currently imposes a personal income tax as well as an income tax on corporations

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and other entities. Texas imposes a margin tax on corporations and limited liability companies. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns required as a result of being a unitholder.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Substantially all of our pipelines, which are located in Texas, Louisiana, Oklahoma, and Kansas are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee.

We believe that we have satisfactory title to all our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Obligations under our 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. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.

Our executive offices occupy two entire floors in an office building at 2001 Bryan Street, Suite 3700, Dallas, Texas, 75201, under a lease that expires on October 31, 2019. We also maintain regional offices located on leased premises in Shreveport, Louisiana, and Midland, Houston, and San Antonio, Texas and Damascus, Arkansas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

For additional information regarding our properties, please read “Item 1—Business.”

Item 3. Legal Proceedings

We are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Neither the Partnership nor any of its subsidiaries, including RGS, is, however, currently a party to any pending or, to our knowledge, threatened material legal or governmental proceedings, including proceedings under any of the various environmental protection statutes to which it is subject.

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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Part II

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

Market Price of and Distributions on the Common Units and Related Unitholder Matters

Our common units were first offered and sold to the public on February 3, 2006. Our common units are listed on NASDAQ under the symbol “RGNC.” As of February 18, 2009, the number of holders of record of common units was 65, including Cede & Co., as nominee for Depository Trust Company, which held of record 48,833,125 common units. Currently, our common units are listed on the Nasdaq Global Select Market. The following table sets forth, for the periods indicated, the high and low quarterly sales prices per common unit, as reported on NASDAQ, and the cash distributions declared per common unit.

	Price Ranges				Cash Distributions (per unit)
Distribution Date	High		Low
2009
First Quarter(2) (through February 18, 2009)	$	12.47	$	8.08		(3)
2008
First Quarter(1)(2)		34.84		25.78	0.4000
Second Quarter(2)		28.73		23.93	0.4200
Third Quarter(2)		26.88		15.75	0.4450
Fourth Quarter(2)		19.00		4.92	0.4450
2007
First Quarter		28.45		25.80	0.3800
Second Quarter		33.45		24.57	0.3800
Third Quarter		35.08		28.50	0.3900
Fourth Quarter		33.37		28.09	0.4000

(1) Excludes the Class E common units which were not entitled to any distributions until they were converted into common units. The Class E common units converted to common units on May 5, 2008.

(2) Excludes the Class D common units which were not entitled to any distributions until they were converted into common units. The Class D common units converted to common units on February 9, 2009.

(3) The cash distribution for the first quarter of 2009 will be determined in April 2009.

Cash Distribution Policy

We distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below. During the subordination period (as defined in our partnership agreement), the common units had the right to receive distributions of available cash from operating surplus in an amount equal to the MQD of $0.35 per quarter, plus any arrearages in the payment of the MQD on the common units from prior quarters, before any distributions of available cash could be made on the subordinated units. Our subordinated units converted to common units on February 17, 2009. If we do not have sufficient cash to pay our distributions as well as satisfy our other operational and financial obligations, our General Partner has the ability to reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments.

Available cash generally means, for any quarter ending prior to liquidation of the Partnership, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

• provide for the proper conduct of our business;

• comply with applicable law or any partnership debt instrument or other agreement; or

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• provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

In addition to distributions on its two percent General Partner interest, our General Partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in the following table.

	Total Quarterly Distribution Target Amount	Marginal Percentage Interest in Distributions
		Unitholders		General Partner
Minimum Quarterly Distribution	$0.35	98	%	2	%
First Target Distribution	up to $0.4025	98		2
Second Target Distribution	above $0.4025 up to $0.4375	85		15
Third Target Distribution	above $0.4375 up to $0.5250	75		25
Thereafter	above $0.5250	50		50

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for further discussion regarding the restrictions on distributions.

Recent Sales of Unregistered Securities

On August 15, 2006, in connection with the TexStar acquisition, we issued 5,173,189 of Class B common units to HMTF Gas Partners as partial consideration for the TexStar acquisition. The total purchase price of the TexStar acquisition was $348,909,000. The Class B common units had the same terms and conditions as our common units, except that the Class B common units were not entitled to participate in 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. The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On September 21, 2006, we entered into a Class C Unit Purchase Agreement with certain purchasers, pursuant to which the purchasers purchased from us 2,857,143 Class C common units representing limited partner interests in the Partnership at a price of $21 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 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. The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On April 2, 2007, in connection with the Pueblo Acquisition, we issued 751,597 common units to Bear Cub Investments, LLC and the members of that company as partial consideration for the Pueblo Acquisition. The total purchase price of the Pueblo acquisition was $54,634,000. The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On January 7, 2008, we issued 4,701,034 of Class E common units as partial consideration for the contribution of ASC’s 95 percent ownership interest in FrontStreet. The total purchase price of the FrontStreet acquisition was $146,766,000. The Class E common units had the same terms and conditions as our common units, except that the Class E common units were not entitled to participate in distributions by the Partnership. The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

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On January 15, 2008, we issued 7,276,506 of Class D common units to CDM OLP GP, LLC, the sole general partner of CDM, and CDMR Holdings, LLC, the sole limited partner of CDM, as partial consideration for the CDM Acquisition. The Class D common units have the same terms and conditions as our common units, except that the Class D common units are not entitled to participate in distributions by the Partnership until converted to 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 converted into common units on a one-for-one basis on February 9, 2009. The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

There have been no other sales of unregistered equity securities during the last three years.

Item 6. 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, 2008, 2007, 2006, and 2005, the one-month period ended December 31, 2004, and the eleven-month period ended November 30, 2004. 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.

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	Regency Energy Partners LP															Regency LLC Predecessor
	Year Ended December 31, 2008			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 Acquisition (December 1, 2004) to December 31, 2004
	(in thousands except per unit data)
Statement of Operations Data:
Total revenue	$	1,863,804		$	1,190,238		$	896,865		$	709,401		$	47,857		$	432,321
Total operating expense		1,699,831			1,130,874			857,005			695,366			45,112			404,251
Operating income		163,973			59,364			39,860			14,035			2,745			28,070
Other income and deductions
Interest expense, net		(63,243	)		(52,016	)		(37,182	)		(17,880	)		(1,335	)		(5,097	)
Loss on debt refinancing		—			(21,200	)		(10,761	)		(8,480	)		—			(3,022	)
Other income and deductions, net		332			1,252			839			733			64			186
Net income (loss) from continuing operations		101,062			(12,600	)		(7,244	)		(11,592	)		1,474			20,137
Discontinued operations		—			—			—			732			—			(121	)
Income tax expense (benefit)		(266	)		931			—			—			—			—
Minority interest		312			305			—			—			—			—
Net income (loss)	$	101,016		$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016
Less:
Net income through January 31, 2006		—			—			1,564
Net income (loss) for partners	$	101,016		$	(13,836	)	$	(8,808	)
General partner interest in net income (loss), including IDR		9,967			(393	)		(176	)
Benefical conversion feature for Class C common units		—			1,385			3,587
Benefical conversion feature for Class D common units		7,199			—			—
Limited partner interest	$	83,850		$	(14,828	)	$	(12,219	)
Basic net income (loss) per common and subordinated unit	$	1.27		$	(0.40	)	$	(0.30	)
Diluted net income (loss) per common and subordinated unit	$	1.24			(0.40	)		(0.30	)
Cash distributions declared per common and subordinated unit		1.71			1.52			0.94
Basic and diluted net loss per Class B common unit		—			—			(0.17	)
Cash distributions declared per Class B common unit		—			—			—
Income per Class C common unit due to beneficial conversion feature		—			0.48			1.26
Cash distributions declared per Class C common unit		—			—			—
Income per Class D common unit due to beneficial conversion feature		0.99			—			—
Cash distributions declared per Class D common unit		—			—			—
Basic and diluted net income per Class E common units		—			1.23			—
Cash Distributions per Class E common unit		—			2.06			—

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	Regency Energy Partners LP															Regency LLC Predecessor
	Year Ended December 31, 2008			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 Acquisition (December 1, 2004) to December 31, 2004
	(in thousands except per unit data)
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	1,703,554		$	913,109		$	734,034		$	609,157		$	328,784
Total assets		2,458,639			1,278,410			1,013,085			806,740			492,170
Long-term debt (long-term portion only)		1,126,229			481,500			664,700			428,250			248,000
Net equity		1,086,252			563,293			212,657			230,962			181,936
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	181,298		$	79,529		$	44,156		$	37,340		$	(4,311	)	$	32,401
Investing activities		(948,629	)		(157,933	)		(223,650	)		(279,963	)		(130,478	)		(84,721	)
Financing activities		734,959			99,443			184,947			242,949			132,515			56,380
Other Financial Data:
Total segment margin(1)	$	455,471		$	214,093		$	156,419		$	76,536		$	6,870		$	69,559
EBITDA(1)		266,559			94,185			69,592			30,191			4,470			35,242
Maintenance capital expenditures		18,247			8,764			16,433			9,158			358			5,548
Segment Financial and Operating Data:
Gathering and Processing Segment:
Financial data:
Segment margin	$	256,380		$	154,761		$	111,372		$	60,864		$	6,262		$	61,347
Operating expenses		82,689			53,496			35,008			22,362			1,655			16,230
Operating data:
Natural gas throughput (MMbtu/d)		1,025,779			772,930			529,467			345,398			314,812			303,345
NGL gross production (Bbls/d)		22,390			21,808			18,587			14,883			16,321			14,487
Transportation Segment:
Financial data:
Segment margin	$	78,161		$	59,332		$	45,047		$	15,672		$	608		$	8,212
Operating expenses		3,614			4,504			4,488			1,929			164			1,556
Operating data:
Throughput (MMbtu/d)		770,939			751,761			587,098			258,194			161,584			192,236
Contract Compression:
Financial data:
Segment margin	$	125,503			N/A			N/A			N/A			N/A			N/A
Operating expenses		49,799			N/A			N/A			N/A			N/A			N/A

(1) See “—Non-GAAP Financial Measures” for a reconciliation to its most directly comparable GAAP measure.

N/A Not applicable as we acquired these assets in January 2008.

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;

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

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

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

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

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

We define total segment margin as total revenues, including service fees, less cost of gas and liquids. 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.

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	Regency Energy Partners LP															Regency LLC Predecessor
	Year Ended December 31, 2008			Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005			Period from Acquisition Date (December 1, 2004) to December 31, 2004			Period from January 1, 2004 to November 30, 2004
	(in thousands)
Reconciliation of “EBITDA” to net cash flows provided by (used in) operating activities and to net (loss) income
Net cash flows provided by (used in) operating activities	$	181,298		$	79,529		$	44,156		$	37,340		$	(4,311	)	$	32,401
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization		(105,324	)		(57,069	)		(39,287	)		(24,286	)		(1,793	)		(10,461	)
Write-off of debt issuance costs		—			(5,078	)		(10,761	)		(8,480	)		—			(3,022	)
Equity income and minority interest in earnings		(312	)		(262	)		532			312			56			—
Risk management portfolio value changes		14,700			(14,667	)		2,262			(11,191	)		322			—
Loss (gain) on asset sales		(472	)		(1,522	)		—			1,254			—			—
Unit based compensation expenses		(4,306	)		(15,534	)		(2,906	)		—			—			—
Gain on insurance settlement		3,282			—			—			—			—			—
Trade accounts receivable and accrued revenues		(18,648	)		28,789			5,506			43,012			(2,568	)		19,832
Other current assets		6,615			1,394			(104	)		2,644			2,456			1,169
Trade accounts payable, accrued cost of gas and liquids and accrued liabilities		40,772			(30,089	)		1,359			(52,651	)		(548	)		(18,122	)
Other current liabilities		(12,749	)		149			(3,640	)		(2,075	)		1,163			(1,977	)
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		(3,840	)		(554	)		(3,283	)		3,261			6,697			196
Net (loss) income	$	101,016		$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016
Add:
Interest expense, net		63,243			52,016			37,182			17,880			1,335			5,097
Depreciation and amortization		102,566			55,074			39,654			23,171			1,661			10,129
Income tax expense		(266	)		931			—			—			—			—
EBITDA	$	266,559		$	94,185		$	69,592		$	30,191		$	4,470		$	35,242
Reconciliation of “total segment margin” to net (loss) income
Net (loss) income	$	101,016		$	(13,836	)	$	(7,244	)	$	(10,860	)	$	1,474		$	20,016
Add (deduct):
Operation and maintenance		131,629			58,000			39,496			24,291			1,819			17,786
General and administrative		51,323			39,713			22,826			15,039			645			6,571
Loss on asset sales		472			1,522			—			—			—			—
Management services termination fee		3,888			—			12,542			—			—			—
Transaction expenses		1,620			420			2,041			—			—			7,003
Depreciation and amortization		102,566			55,074			39,654			23,171			1,661			10,129
Interest expense, net		63,243			52,016			37,182			17,880			1,335			5,097
Loss on debt refinancing		—			21,200			10,761			8,480			—			3,022
Other income and deductions, net		(332	)		(1,252	)		(839	)		(733	)		(64	)		(186	)
Discontinued operations		—			—			—			(732	)		—			121
Income tax expense		(266	)		931			—			—			—			—
Minority interest		312			305			—			—			—			—
Total segment margin	$	455,471		$	214,093		$	156,419		$	76,536		$	6,870		$	69,559

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Item 7. 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 and Oklahoma.

OUR OPERATIONS. We divide our operations into three business segments:

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

• Transportation: We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system. The Partnership, GE EFS and Alinda entered into a definitive agreement to form a joint venture to finance and construct the Partnership’s previously announced Haynesville Expansion Project. This project will more than double the capacity of RIGS in north Louisiana to bring natural gas from the Haynesville Shale, one of the most active new natural gas plays in the United States. The Partnership has secured commitments from shippers for 925 MMcf/d, which is more than 84 percent of the capacity of the Haynesville Expansion Project, and is in negotiations for the remaining capacity. The agreements are for firm transportation capacity under 10-year contract terms; and

• Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 762,000 horsepower of compression in Texas, Louisiana, and Arkansas. In addition, our contract compression segment operates approximately 196,000 horsepower of compression for our gathering and processing and transportation segments.

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 and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline in commodity prices, however, could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments.

• Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we

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retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component).

• 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) 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, (2) fixed cash fees for ancillary services, such as gathering, treating, and compression, (3) the ability to bypass processing in unfavorable price environments or (4) “conditioning floor” fees that apply in adverse 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. For example, 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, natural gas, and natural gasoline 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.

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• 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 our Regency Intrastate Pipeline system. 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.

The Partnership, GECC and the Alinda Investors entered into a definitive agreement to form a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas from the Haynesville Shale, one of the fastest growing natural gas plays in the United States. In connection with the joint venture, we will contribute all of our ownership interests in RIGS, valued at $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. GECC and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.

We will serve as the operator of the joint venture, and will provide all employees and services for the operation and management of the joint venture’s assets. We expect to close the joint venture transaction as promptly as practicable following the satisfaction of the closing conditions, but no later than April 30, 2009. Please read “Item 1—Business—Overview.”

Contract compression segment. We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 778,000 horsepower of compression for third party producers in Texas, Louisiana, and Arkansas. In addition, our contract compression segment operates approximately 196,000 horsepower of compression for our gathering and processing and transportation segments.

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, total 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

47

obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) 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.

We calculate our contract compression segment margin as revenue generated minus direct operating costs.

Total Segment Margin. Segment margin from gathering and processing, transportation, and contract compression segments comprise total segment margin. We use total segment margin as a measure of performance. See “Item 6. 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 unitholders and general partner;

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

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

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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 “Item 6—Selected Financial Data” 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.

Even though overall drilling activity is forecasted to decline, drilling in the Haynesville Shale formation is expected to increase. According to Energy Intelligence (www.energyintel.com), the number of horizontal rigs at work in Haynesville has increased by 6 percent since October 2008. According to the report, several companies are shifting resources from the more developed Barnett Shale formation to the Haynesville Shale formation. The increased level of drilling activity is attributed to its resource potential and the producers’ obligation to drill to maintain the terms of their recently leased acreage.

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.

Effect of Interest Rates and Inflation. Interest rates on existing and future credit facilities and debt offerings could be significantly 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.

49

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 depreciation, 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.

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, indirect subsidiaries 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 and 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. The Partnership was not required to record any adjustments to reflect the acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions.

Acquisition of FrontStreet. On January 7, 2008, we acquired all of the outstanding equity and minority interest (the “FrontStreet Acquisition”) of FrontStreet from ASC and EnergyOne. 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) $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract valued at $3,888,000. We financed the cash portion of the purchase price with borrowings under our revolving credit facility.

Because the acquisition of ASC’s 95 percent interest is a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method.

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Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which we applied the purchase method of accounting.

Acquisition of CDM. On January 15, 2008, we and an indirect wholly owned subsidiary (“Merger Sub”) consummated an agreement and plan of merger (the “Merger Agreement”) with CDM Resource Management, Ltd. The total purchase price consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations. The results of operations of CDM are included in our statements of operations beginning January 16, 2008.

Acquisition of Nexus. On March 25, 2008, we acquired Nexus by merger for $88,640,000 in cash, including customary closing adjustments. The results of operations of Nexus are included in our statements of operations beginning March 26, 2008.

RESULTS OF OPERATIONS

Year Ended December 31, 2008 vs. Year Ended December 31, 2007

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

	Year Ended December 31,
	2008			2007			Change			Percent
	(in thousands)
Total revenues	$	1,863,804		$	1,190,238		$	673,566		57	%
Cost of sales		1,408,333			976,145			432,188		44
Total segment margin(1)		455,471			214,093			241,378		113
Operation and maintenance		131,629			58,000			73,629		127
General and administrative		51,323			39,713			11,610		29
Loss on asset sales, net		472			1,522			(1,050	)	69
Management services termination fee		3,888			—			3,888		n/m
Transaction expenses		1,620			420			1,200		286
Depreciation and amortization		102,566			55,074			47,492		86
Operating income		163,973			59,364			104,609		176
Interest expense, net		(63,243	)		(52,016	)		(11,227	)	22
Loss on debt refinancing		—			(21,200	)		21,200		n/m
Other income and deductions, net		332			1,252			(920	)	73
Income (loss) before income taxes		101,062			(12,600	)		113,662		902
Income tax expense (benefit)		(266	)		931			(1,197	)	129
Minority interest		312			305			7		2
Net income (loss)	$	101,016		$	(13,836	)	$	114,852		830
System inlet volumes (MMBtu/d)(2)		1,522,431			1,225,918			296,513		24	%

(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data.”

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

n/m not meaningful

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

	Year Ended December 31,
	2008		2007		Change			Percent
	(in thousands)
Gathering and Processing Segment
Financial data:
Segment margin(1)	$	256,380	$	154,761	$	101,619		66	%
Operation and maintenance(2)		82,689		53,496		29,193		55
Operating data:
Throughput (MMBtu/d)(3)		1,025,779		772,930		252,849		33
NGL gross production (Bbls/d)		22,390		21,808		582		3
Transportation Segment
Financial data:
Segment margin(1)	$	78,161	$	59,332	$	18,829		32	%
Operation and maintenance(2)		3,614		4,504		(890	)	20
Operating data:
Throughput (MMBtu/d)(3)		770,939		751,761		19,178		3
Contract Compression
Financial data:
Segment margin(1)	$	125,503	$	—		N/A		N/A
Operation and maintenance(2)		49,799		—		N/A		N/A

(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data.” Combined segment margin for our segments differs from consolidated total segment margin due to inter-segment eliminations.

(2) Combined operation and maintenance expense for our segments differs from consolidated operation and maintenance expense due to inter-segment eliminations.

(3) Combined throughput volumes for the gathering and processing and transportation segment vary from consolidated system inlet volumes due to inter-segment eliminations.

N/A Not applicable as we acquired these assets in January 2008.

Net Income. Net income for the year ended December 31, 2008 increased $114,852,000 or 830 percent, compared with the year ended December 31, 2007. The increase in net income was primarily attributable to an increase in total segment margin of $241,378,000 and the absence in the current period of a $21,200,000 loss on debt refinancing related to the termination penalty associated with the redemption of 35 percent of our senior notes. The increase in total segment margin was primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth in the gathering and processing segment. We were required to use the as-if pooling method of accounting described in SFAS No. 141, “Business Combinations” for our FrontStreet acquisition because it involved entities under common control. Common control began on June 18, 2007; therefore the discussion below includes activity from FrontStreet from June 18, 2007 forward even though the acquisition occurred in January 2008. Partially offsetting these increases in net income were:

• an increase in operation and maintenance expense of $73,629,000 primarily due to our contract compression and FrontStreet assets acquired in January 2008 and increases in organic growth-related maintenance and employee-related expenses mainly in the gathering and processing segment;

• an increase in depreciation and amortization expense of $47,492,000 primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth projects primarily in the gathering and processing segment;

• an increase in general and administrative expenses of $11,610,000 primarily due to our contract compression assets acquired in January 2008 and increased employee-related expenses, reduced by the

52

absence of an $11,928,000 expense associated with the vesting of all outstanding LTIP grants incurred in 2007 when GE EFS acquired our general partner;

• an increase in interest expense of $11,227,000 primarily due to increased levels of borrowings; and

• a payment of a management contract services termination fee of $3,888,000 in 2008 related to the acquisition of FrontStreet.

Segment Margin. Total segment margin for the year ended December 31, 2008 increased $241,378,000 compared with the year ended December 31, 2007. This increase was attributable to an increase of $101,619,000 in gathering and processing segment margin and an increase of $18,829,000 in transportation segment margin and the addition of $125,503,000 in contract compression segment margin, discussed below. Combined segment margin for our segments differs from consolidated total segment margin due to inter-segment eliminations of $4,573,000.

Gathering and processing segment margin increased to $256,380,000 for the year ended December 31, 2008 from $154,761,000 for the year ended December 31, 2007. The major components of this increase were as follows:

• $29,657,000 from non-cash changes in the value of certain risk management contracts related to our hedging programs;

• $25,274,000 from a full year’s operation of our FrontStreet assets which were consolidated on June 18, 2007;

• $19,200,000 from increased throughput and organic growth in south Texas;

• $11,770,000 from increased throughput and organic growth in north Louisiana;

• $9,548,000 from increased sulfur prices;

• $7,589,000 from the operations of our Nexus assets; and partially offset by

• $(1,419,000) from other sources.

Transportation segment margin increased to $78,161,000 for the year ended December 31, 2008 from $59,332,000 for the year ended December 31, 2007. The major components of this increase were as follows:

• $12,440,000 from increased operational efficiencies coupled with increased commodity prices;

• $4,705,000 in increased margins associated with our limited marketing function; and

• $1,684,000 from increased throughput volumes and changes in contract mix.

Contract compression segment margin was $125,503,000 in the year ended December 31, 2008, which consisted of $137,122,000 of operating revenue and $11,619,000 of direct operating cost.

Operation and Maintenance. Operations and maintenance expense increased to $131,629,000 in the year ended December 31, 2008 from $58,000,000 for the corresponding period in 2007, a 127 percent increase. This increase is primarily the result of the following factors:

• $45,326,000 related to our contract compression assets acquired in January 2008, net of intercompany eliminations;

• $14,972,000 related to our FrontStreet assets, which are operated by a third party;

• $8,864,000 related primarily to the gathering and processing segment associated with organic growth projects since December 31, 2007 involving compressor and other maintenance expenses in 2008;

• $2,726,000 increase in employee-related expenses primarily related to increases in annual salaries, bonus accrual and employer benefit payments mostly in the gathering and processing segment;

• $1,316,000 increase in utility expense due to higher commodity prices primarily in the gathering and processing segment;

53

• $1,227,000 increase in contractor expense in the transportation segment due to compressor maintenance; and

• partially offset by a $1,393,000 increase in insurance proceeds received in August 2008 ($3,134,000) versus November 2007 ($1,741,000) related to a March 2007 compressor fire in the transportation segment.

General and Administrative. General and administrative expense increased to $51,323,000 in the year ended December 31, 2008 from $39,713,000 for the same period in 2007, a 29 percent increase. In June 2007, the Partnership incurred a one-time charge of $11,928,000 associated with the vesting of all outstanding common unit options upon a change in control of our general partner. Absent this expense, general and administrative expenses increased by $23,538,000 primarily due to:

• $16,224,000 related to our contract compression assets acquired in January 2008;

• $5,788,000 increase in employee-related expenses primarily due to hiring of new employees, employer benefit payments and bonus accruals; and

• $958,000 increase in legal expenses.

Management Services Termination Fee. In 2008, we recorded $3,888,000 for the termination of a long-term management services contract associated with our FrontStreet acquisition.

Depreciation and Amortization. Depreciation and amortization expense increased to $102,566,000 in the year ended December 31, 2008 from $55,074,000 for the year ended December 31, 2007, an 86 percent increase. The increase was primarily due to:

• $28,448,000 related to our contract compression assets acquired in January 2008;

• $8,440,000 related to our FrontStreet assets which for the year ended December 31, 2008 are being depreciated over a shorter useful life as compared to 2007 and the year ended December 31, 2008 includes a full year where as the year ended December 31, 2007 only included six months of depreciation;

• $7,428,000 related to various organic growth projects completed since December 31, 2007, primarily in the gathering and processing segment; and

• $3,176,000 related to our Nexus assets acquired in March 2008.

Interest Expense, Net. Interest expense, net increased $11,227,000, or 22 percent, in the year ended December 31, 2008 compared to the same period in 2007. Of this increase, $26,266,000 was attributable to increased levels of borrowings partially offset by $15,039,000 primarily attributable to lower interest rates.

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.

54

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)
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		(12,600	)		(7,244	)		(5,356	)	74
Income tax expense		931			—			931		n/m
Minority interest		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 reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data.”

(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

55

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)
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 “Item 6. Selected Financial Data.”

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.

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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.

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;

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• $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.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

• cash generated from operations;

• borrowings under our credit facility;

• operating lease facilities;

• debt offerings; and

• issuance of additional partnership units.

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, particularly as a result of our Haynesville Expansion Project. At December 31, 2008, the Partnership has purchase obligations totaling approximately $323,341,000, of which $104,852,000 is related to the purchase of major compression components unrelated to the Haynesville Expansion Project, that extend until the year ending December 31, 2010 and $218,489,000 of which is related to the Haynesville Expansion Project that extend until the year ending December 31, 2009. Some of these commitments have cancellation provisions.

The Partnership, GECC and the Alinda Investors entered into a definitive agreement to form a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas

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from the Haynesville Shale, one of the fastest growing natural gas plays in the United States. In connection with the joint venture, we will contribute all of our ownership interests in RIGS, valued at $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. The GE Investor and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.

In the future, the management committee of the joint venture may request that we make additional capital contributions to support the joint venture’s capital expenditures. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations. In addition, we have agreed to reimburse the joint venture for the first $20,000,000 of cost overruns relating to the Haynesville Expansion Project.

The Partnership has secured commitments from shippers for 925 MMcf/d, which is more than 84 percent of the capacity of the Haynesville Expansion Project, and is in negotiations for the remaining capacity. The agreements are for firm transportation capacity under 10-year contract terms.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding. The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. We expect that our ability to issue debt and equity at prices that are similar to offerings in recent years will be limited as long as capital markets remain constrained. Our planned internal growth projects continue to require us to bear the cost of constructing these new assets before we begin to realize a return on them. As a result, we will continue to be opportunistic in our approach to funding the remaining expenditures from additional issuances of our equity and long-term debt.

Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. For example, as a result of Lehman filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a subsidiary of Lehman that is a committed lender under our credit facility has declined requests to honor its commitment to lend under our credit facility. The total amount available to us under our credit facility as of February 20, 2009 was $42,410,000, which has been reduced by the amount of Lehman’s commitment of $5,578,000 that is no longer available to us. If we repay any of the amounts we have already borrowed from Lehman, we may not be able to reborrow such amounts. We may be unable to utilize the full borrowing capacity under our credit facility if other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that Lehman’s subsidiary has refused to fund or if any of the remaining committed lenders are unable or unwilling to fund their respective portion of any funding request we make under our credit facility.

In addition, we have entered into a $75,000,000 operating lease facility with Caterpillar Financial Services Corporation and a $45,000,000 revolving credit facility with GECC as further described below.

We expect to reduce our growth capital expenditures in 2009 and 2010, from approximately $300,000,000 per year to approximately $120,000,000 in 2009 and $100,000,000 in 2010. As a result of our reduced capital expenditure plans, our need to access the debt and equity markets will be significantly reduced.

Although we intend to move forward with our planned internal growth projects, we may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our expansion activities may be muted by substantial cost of capital increases during this period. As a result of these costs our cash flows may decrease, which could impair our liquidity position and require us to reduce our distributions to unitholders.

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Finally, if there is a significant lessening in demand for our services as a result of extended declines in the actual and longer term expected price of oil and gas, we may see a further reduction in our own capital expenditures and lesser requirements for working capital, both of which could generate operating cash flow and liquidity compared to the prior period and offset reduced cash generated from operations excluding working capital changes. However, such an environment might also increase the availability of acquisitions which could draw on such liquidity.

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. When we incur growth capital expenditures, we experience working capital deficits as 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 12 months, and so must be viewed differently from trade accounts receivable and accounts payable which settle over a much shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect risk management assets and liabilities to affect our ability to pay bills as they come due. Our contract compression segment records deferred revenues, a current liability. The deferred revenues represent billings in advance of services performed. As the revenues associated with the deferred revenues are earned, the liability is reduced.

Our working capital surplus at December 31, 2008 was $19,453,000 as compared to a working capital deficit of $18,365,000 at December 31, 2007, a $37,818,000 increase primarily due to the following factors:

• a $69,154,000 increase in working capital due to the value of risk management activities shifting from current liabilities to current assets resulting from a decrease in commodity prices we expect to pay (index prices) on our outstanding swaps versus the fixed commodity prices we expect to receive upon settlement;

• $7,170,000 increase in working capital resulting from an increase in net account receivable and payable due to the timing of cash receipts and payments;

• a $6,615,000 increase in working capital resulting from an increase in other current assets primarily due to an increase in insurance and other pre-paid expenses of $3,887,000, equipment inventory of $1,567,000, and NGL inventory of $1,041,000; and

Partially offsetting these increases in working capital were the following factors:

• a decrease in cash and cash equivalents of $32,372,000 due to the timing of cash receipts and payments associated with ongoing business operations; and

• an increase in other current liabilities of $12,749,000 primarily related to an increase in deferred revenues associated with business operations of our contract compression segment.

Cash Flows from Operating Activities. Net cash flows provided by operating activities increased $101,769,000, or 128 percent, for the year ended December 31, 2008 as compared to the year ended December 31, 2007. Cash generated from operations increased primarily due to increased total segment margin of $241,378,000, primarily due to operating activity of our contract compression, FrontStreet and Nexus assets acquired in the first calendar quarter of 2008 and organic growth in the gathering and processing segment.

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 on June 18, 2007.

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

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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, 2008 and 2007 were $809,000,000 and $178,930,000, respectively.

Cash Flows from Investing Activities. Net cash flows used in investing activities increased $790,696,000 or 501 percent, in the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase is primarily due to organic growth in the gathering and processing segment and cash consideration paid for the contract compression, FrontStreet, and Nexus assets in the first calendar quarter of 2008.

Growth Capital Expenditures. In the year ended December 31, 2008, we incurred $354,727,000 of growth capital expenditures. Growth capital expenditures for the year ended December 31, 2008 primarily relate to the following projects:

• $176,740,000 for the fabrication of new compression packages and ancillary assets for our contract compression segment;

• $123,383,000 for various projects in the gathering and processing segment, primarily in Louisiana and Texas; and

• $54,604,000 in our transportation segment for the Haynesville Expansion Project.

Maintenance Capital Expenditures. In the year ended December 31, 2008, we incurred $18,247,000 of maintenance capital expenditures. Maintenance capital expenditures primarily consist of compressor and plant overhauls, as well as replacement or repair of equipment.

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 $12,639,000, partially offset by our 2007 Pueblo acquisition ($34,855,000).

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased $635,516,000, or 639 percent, in the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily due to the following:

• an increase in net borrowings under our revolving credit facility of $585,429,000 due to increased borrowings associated with organic growth primarily in the gathering and processing segment and our contract compression, FrontStreet, and Nexus acquisitions;

• the absence in 2008 of the 35 percent redemption of our senior notes in 2007 of $192,500,000; and partially offset by

• a decrease in proceeds from equity issuances of $154,231,000.

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;

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• 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; and

• an increase in FrontStreet and contribution of $9,695,000 and $13,417,000 respectively.

Capital Resources

Description of Our Indebtedness. As of December 31, 2008, our aggregate outstanding indebtedness totaled $1,126,229,000 and consisted of $768,729,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes as compared to our aggregate outstanding indebtedness as of December 31, 2007, which totaled $481,500,000 and consisted of $124,000,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes.

Credit Ratings. Our credit ratings as of December 31, 2008 are provided below.

	Moody’s	Standard & Poor’s
Regency Energy Partners LP
Corporate rating/total debt	Ba3	BB-
Senior notes	B1	B
Outlook	Negative Outlook	Negative Outlook

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 or term loan 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 certain subsidiaries, by the Partnership and each such subsidiary. The revolving loans mature at the maturity of the credit facility in August 2011. Interest on revolving loans thereunder will be calculated, at our option, at either: (a) a base rate that is the greater of (i) a base rate plus the applicable margin and (ii) a federal funds effective rate plus 0.50 percent plus the applicable margin, or (b) an adjusted LIBOR rate plus the applicable margin. The applicable margin that is used in calculating interest shall range from 0.50 percent to 1.25 percent for base rate loans and from 1.50 percent to 2.25 percent for Eurodollar loans. 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 6.27 percent for the year ended December 31, 2008. We must pay (i) a commitment fee ranging from 0.300 percent to 0.500 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.

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Credit Agreement Amendment. On February 26, 2009, RGS entered into Amendment Agreement No. 7 (the “Amendment”) with Wachovia Bank, National Association, as administrative agent, and the lenders party thereto in order to amend the Credit Agreement. The Amendment will become effective upon the closing of the Contribution Agreement of the joint venture and the satisfaction of certain other conditions precedent.

Upon its effectiveness, the Amendment, among other things, (a) authorizes the contribution by Regency HIG of its ownership interests in RIGS to the joint venture and future investments in the joint venture of up to $135,000,000 in the aggregate, (b) permits distributions by RGS to the Partnership in an amount equal to the outstanding loans, interest and fees under a $45,000,000 revolving credit facility with GECC entered into on February 26, 2009, (c) adds an additional financial covenant that limits the ratio of senior secured indebtedness to EBITDA, (d) provides for certain EBITDA adjustments in connection with the Haynesville Expansion Project, and (e) increases the applicable margins and commitment fees applicable to the credit facility, as further described below.

Upon the effectiveness of the Amendment, (a) the alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent, (b) the applicable margin that is used in calculating interest shall range from 1.50 percent to 2.25 percent for base rate loans and from 2.50 percent to 3.25 percent for Eurodollar loans, and (c) commitment fees will range from 0.375 percent to 0.50 percent.

The Amendment prohibits RGS or its subsidiaries from allowing the joint venture to incur or permit to exist any preferred interests or indebtedness for borrowed money of the joint venture prior to the completion date of the Haynesville Expansion Project. RGS and GECC executed a side letter on February 26, 2009 confirming that, after the closing of the Contribution Agreement, they will not permit their representatives on the management committee of the joint venture to violate such restriction.

Revolving Credit Facility. On February 26, 2009, we entered into a $45,000,000 unsecured revolving credit agreement with GECC, as administrative agent, the lenders party thereto and the guarantors party thereto (the “Revolving Credit Facility”). The proceeds of the Revolving Credit Facility may be used for expenditures made in connection with the Haynesville Expansion Project prior to the earlier to occur of the effectiveness of the Amendment and April 30, 2009. The commitments under the Revolving Credit Facility will terminate automatically on the earlier to occur of the effectiveness of the Amendment and April 30, 2009, and the Partnership will be required to prepay all outstanding loans upon the effectiveness of the Amendment. The maturity date under the Revolving Credit Facility will be the earlier of the date that is three months after the final maturity date under the Credit Agreement and November 15, 2011.

Interest will be calculated, at our option, at either (a) the greater of (i) a federal funds effective rate plus 0.50 percent plus the applicable margin or (ii) an adjusted LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent plus the applicable margin and (b) an adjusted LIBOR rate plus the applicable margin. The applicable margin that is used in calculating interest shall range from 3.00 percent to 10.00 percent for base rate loans and from 4.00 percent to 11.00 percent for Eurodollar loans. The Partnership shall pay a 6 percent origination fee. The Partnership shall pay a commitment fee of 0.75 percent per annum on the unused portion of the commitments under the Revolving Credit Facility.

We are required to comply with the covenants set forth in the Credit Agreement and in the Partnership’s Indenture dated as of December 12, 2006 among us, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee. The Revolving Credit Facility is guaranteed by our subsidiaries (as defined in the Revolving Credit Facility) (other than RIGS, unless the Amendment does not become effective by April 30, 2009).

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Letters of Credit. At December 31, 2008, we had outstanding letters of credit totaling $16,257,000. 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 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. 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.

The senior notes are initially guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”), except certain wholly owned subsidiaries. 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, 2008, we were in compliance with these covenants.

Equity Offering. On August 1, 2008, the Partnership sold 9,020,000 common units for an average price of $22.18 per unit. The Partnership received $204,133,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution of $4,082,653. As of December 31, 2008 the Partnership has incurred $34,000 in costs related this equity offering. An affiliate of GECC purchased 2,272,727 of these common units. The Partnership used the proceeds from its equity offering to repay a portion of its credit facility.

Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations as of December 31, 2008.

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Operating Lease Facility. CDM entered into an operating lease facility with Caterpillar Financial Services Corporation whereby CDM has the ability to lease compression equipment with an aggregate value of up to $75,000,000. The facility is available for leases with inception dates up to and including December 31, 2009, and mitigates the need to use available capacity under the existing Credit Facility. Each compressor acquired under this facility shall have a lease term of one hundred twenty (120) months with a fair value buyout option at the end of the lease term. At the end of the lease term, CDM shall also have an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fair market rate at that time. In the event CDM elects not to exercise the buyout option, the equipment must be returned in a manner fit for use at the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions exist at month sixty (60) and at month eighty four (84) of the one hundred twenty (120) month lease term. Covenants under the lease facility require CDM to maintain certain fleet utilization levels as of the end of each calendar quarter as well as a total debt to EBITDAR (Earnings Before Interest, Taxes, Depreciation, Amortization, and Rental expense) ratio of less than or equal to 4:1. In addition, covenants restrict the concentration of revenues derived from the equipment acquired under the lease facility. The terms of the lease facility do not include contingent rentals or escalation clauses.

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2008.

	Payment Due by Period
	Total		2009		2010-2011		2012-2013		Thereafter
	(in thousands)
Long-term debt (including interest)(1)	$	1,217,870	$	53,433	$	747,056	$	417,381	$	—
Capital leases		10,099		612		1,015		910		7,562
Operating leases		15,490		2,357		4,874		2,786		5,473
Purchase obligations		323,341		320,321		3,020		—		—
Total(2)(3)	$	1,566,800	$	376,723	$	755,965	$	421,077	$	13,035

(1) Assumes a constant LIBOR interest rate of 2.0 plus applicable margin (1.5 percent as of December 31, 2008) for our revolving credit facility. The principal of our outstanding senior notes ($357,500,000) bears a fixed rate of 8 3/8 percent.

(2) Excludes physical and financial purchases of natural gas, NGLs, and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily and 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 $8,156,000 as the amount payable by period can not be readily estimated in light of 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. 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. For information regarding environmental matters, please read “Item 1 Business—Regulation—Environmental Matters.”

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.

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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.

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.

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.

Goodwill Valuation.The Partnership reviews the carrying value of goodwill on a regular basis, including December 31 of each year, for indicators of impairment at each reporting unit that has recorded goodwill. The Partnership determines its reporting units based on identifiable cash flows of the components of a segment and how segment managers evaluate the results of operations of the entity. Impairment is indicated whenever the carrying value of a reporting unit exceeds the estimated fair value of a reporting unit. For purposes of evaluating impairment of goodwill, the Partnership estimates the fair value of a reporting unit based upon future net discounted cash flows. In calculating these estimates, historical operating results and anticipated future economic factors, such as estimated volumes and demand for compression services, commodity prices, and operating costs are considered as a component of the calculation of future discounted cash flows. The estimates of fair value of these reporting units could change if actual volumes, prices, costs or expenses vary from these estimates.

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Based on the Partnership’s annual impairment testing on December 31, 2008, no impairment was identified. If current credit issues and market volatility continue to deteriorate, the Partnership’s goodwill could be impaired and have a material impact on future earnings of the Partnership.

Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, transmission pipelines, and natural gas compression equipment. 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. 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.

As-if Pooling of Interest Method of Accounting. We account for acquisitions where common control exists by following the as-if pooling method of accounting as described in SFAS No. 141, “Business Combinations.” Under this method of accounting, we reflect the historical balance sheet data for both the acquirer and acquiree instead of reflecting the fair market value of acquiree’s assets and liabilities. In common control acquisitions where a minority interest is also acquired, we use the purchase method of accounting for the minority interest. Further, certain transaction costs that would normally be capitalized are expensed.

Fair Value Measurements. On January 1, 2008, we adopted the provisions of SFAS No. 157 for financial assets and liabilities. SFAS No. 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations. SFAS No. 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

• Level 1—unadjusted quoted prices for identical assets or liabilities in active markets accessible by us;

• Level 2—inputs that are observable in the marketplace other than those inputs classified as Level 1; and

• Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

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SFAS No. 157 encourages us to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument valuation uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation. Our financial assets and liabilities measured at fair value on a recurring basis are derivative financial instruments consisting of interest rate swaps and commodity swaps.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities related to interest rate and commodity swaps. Risk management assets and liabilities are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. The Partnership has no financial assets and liabilities as of December 31, 2008 valued based on inputs classified as Level 3 in the hierarchy.

RECENT ACCOUNTING PRONOUNCEMENTS

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

Item 7A. 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. 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.

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We are a net seller of NGLs, natural gas and condensate, and as such our financial results are exposed to fluctuations in commodity pricing. We have executed swap contracts settled against condensate, ethane, propane, butane, natural gas, 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 for below:

	2009		2010
NGL	97	%	33	%
Condensate	76	%	76	%
Natural gas	63	%	0	%

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

In March 2008, the Partnership entered offsetting trades against its existing 2009 portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its existing 2009 hedges. 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.

In May 2008, the Partnership entered into one-year commodity swaps to hedge its 2010 NGL commodity risk, except for ethane, which are accounted for using mark-to-market accounting. We chose to delay hedging our 2010 exposure to ethane due to our perception that the prices offered by the counterparties were sharply discounted from comparable forward crude prices. We expect to hedge our ethane exposure in the future.

The Partnership accounts for a portion of its 2008 and all of its 2009 West Texas Intermediate crude oil swaps using mark-to-market accounting. In May 2008, the Partnership entered into a one-year West Texas Intermediate crude oil swap to hedge its 2010 condensate risk, which was designated as a cash flow hedge in June 2008.

The following table sets forth certain information regarding our non-trading NGL swaps outstanding at December 31, 2008. 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	Underlying	Notional Volume/ Amount			We Pay	We Receive		Fair Value Asset/(Liability)
								(in thousands)
January 2009-December 2009	Ethane		701	(MBbls)	Index	$0.80	($/gallon)	$	10,827
January 2009-December 2010	Propane		694	(MBbls)	Index	$0.9815 - $1.5325	($/gallon)		16,726
January 2009-December 2010	Iso Butane		157	(MBbls)	Index	$1.685 - $1.915	($/gallon)		6,172
January 2009-December 2010	Normal Butane		299	(MBbls)	Index	$1.166 - $1.895	($/gallon)		7,737
January 2009-December 2010	Natural Gasoline		310	(MBbls)	Index	$1.4975 - $2.53	($/gallon)		14,033
January 2009-December 2010	West Texas Intermediate Crude		475	(MBbls)	Index	$68.17 - $121.30	($/Bbl)		16,650
January 2009-December 2010	Natural Gas		3,650,000	(MMBtu)	Index	$6.67 - $6.705	($/MMBtu)		2,134
January 2009-March 2010	Interest Rate	$	300,000,000		2.40%	One-month	LIBOR		(5,239	)
Credit risk adjustment	Credit risk adjustment								(1,500	)
Total Fair Value								$	67,540

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.

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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. 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. 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. At December 31, 2008, 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, 2008, we had $468,729,000 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 $4,687,000. On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (1.5 percent as of December 31, 2008) through March 5, 2010. These interest rate swaps were designated as cash flow hedges in March 2008.

Item 8. Financial Statements and Supplementary Data

The financial statements set forth starting on page F-1 of this report are incorporated by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On June 18, 2007, Deloitte & Touche LLP (“Deloitte”) advised the Partnership that, in light of the change of control from HM Capital to GE EFS and because of existing relationships with GE, effective as of the date of the change of control of the Partnership, Deloitte would no longer be able to serve as the Partnership’s independent registered public accounting firm because it would no longer satisfy the independence requirements necessary to certify the financial statements of the Partnership. As a result, Deloitte resigned as the Partnership’s independent registered public accounting firm, effective as of June 18, 2007.

Deloitte has expressed an unqualified opinion on the consolidated financial statements of the Partnership for the years ended December 31, 2006 and 2005. Such opinion included an explanatory paragraph related to the Partnership’s accounting for its acquisition of TexStar as entities under common control in a manner similar to a pooling of interests. During the two most recent fiscal years and interim period preceding Deloitte’s resignation, there were no disagreements with Deloitte and no reportable events as defined under Item 304(a)(1)(v) of Regulation S-K. A copy of Deloitte’s letter dated June 18, 2007 is incorporated by reference as Exhibit 16.1.

On June 18, 2007, the Board of Directors of the General Partner, subject to approval of the engagement terms by the Audit Committee, requested KPMG LLP (“KPMG”) to act as the independent registered public accounting firm in auditing the financial statements of the Partnership for the year ending December 31, 2007 and in performing such other attestation services for the Partnership as may be required for the remainder of calendar year 2007. On June 26, 2007, the Audit Committee of the Partnership approved the engagement terms of KPMG and authorized KPMG to serve as the Partnership’s independent registered public accountants for the fiscal year ending December 31, 2007.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information

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required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate to allow timely decisions regarding required disclosure.

Our management does not expect that our disclosure controls and procedures will prevent all errors. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all our disclosure control issues have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives.

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based on management’s evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in achieving that level of reasonable assurance as of December 31, 2008.

Internal Control over Financial Reporting.

(a) Management’s Report on Internal Control over Financial Reporting. Management of our General Partner is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for the Partnership as defined in Rules 13a-15(f) as promulgated under the Exchange Act, as amended.

Those rules define internal control over financial reporting as a process designed by, or under the supervision of our General Partner’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and include those policies and procedures that:

• Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Partnership’s assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of our General Partner’s management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statement.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of our General Partner assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of

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the Treadway Commission (the “COSO Framework”). The evaluation included an evaluation of the design of the Partnership’s internal control over financial reporting and testing of the operating effectiveness of those controls.

On January 15, 2008, the Partnership acquired CDM. Management has acknowledged that it is responsible for establishing and maintaining a system of internal controls over financial reporting for CDM. The Partnership excluded CDM from its December 31, 2008 assessment of the effectiveness of internal controls over financial reporting. The Partnership initiated in early 2008 a program of documentation, implementation and testing of internal control over financial reporting for CDM. This program will continue throughout this year, culminating with the sub-certification and attestation by CDM management to the Partnership’s senior management in support of the Partnership’s Section 404 certification and attestation in early 2010. The impact of the acquisition of CDM has not materially affected and is not expected to materially affect the Partnership’s internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and they may be changed. The Partnership believes, however, it will be able to maintain sufficient controls over the substantive results of its financial reporting throughout this integration process.

CDM had total assets of $881,552,000 and total external revenues of $132,549,000 included in the consolidated financial statements of Regency Energy Partners LP as of and for the year ended December 31, 2008.

Based on its assessment, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2008.

(b) Audit Report of the Registered Public Accounting Firm. KPMG LLP, the independent registered public accounting firm that audited the Partnership’s consolidated financial statements included in this report, has issued an audit report on the Partnership’s internal control over financial reporting, which report is included herein on page F-3.

(c) Changes in Internal Control over Financial Reporting. As required by Exchange Act Rule 13a-15(f), management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, also conducted an evaluation of the Partnership’s internal control over financial reporting to determine whether any change occurred during the last fiscal quarter of the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting. Based on that evaluation, there has been no change in the Partnership’s internal control over financial reporting during the last fiscal year of the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Item 9B. Other Information

None.

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

Management. Our General Partner manages and directs all of our activities. Our officers and directors are officers and directors of the General Partner. The owner of the General Partner may appoint up to ten persons to serve on the Board of Directors of the General Partner. Although there is no requirement that he do so, the President and Chief Executive Officer of the General Partner is currently a director of the General Partner and serves as Chairman of the Board of Directors.

Our Board of Directors is currently comprised of its Chairman (the President and Chief Executive Officer of the General Partner), three persons who qualify as “independent” under NASDAQ standards for audit committee members and five persons who were either appointed by the sole member of the General Partner or elected by the other members of the Board of Directors.

Corporate Governance. The Board of Directors has adopted Corporate Governance Guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a Code of Business Conduct, which sets forth legal and ethical standards of conduct for all our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our General Partner. The Corporate Governance Guidelines, the Code of Business Conduct, Code of Conduct of Senior Financial Officers, and the charters of our audit, compensation, nominating, and executive committees are available on our website at www.regencygasservices.com. You may also contact our investor relations department at (214) 840-5467 for printed copies of these documents free of charge. Amendments to, or waivers from, the Code of Business Conduct will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the Code of Business Conduct may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Conflicts Committee. The Board of Directors appoints independent directors as members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to us and our common unitholders. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the General Partner or its Board of Directors of any duties they may owe us or the common unitholders. The Conflicts Committee, like the Audit Committee, is composed only of independent directors.

Audit Committee. The Board of Directors has established an Audit Committee in accordance with Exchange Act rules. The Board of Directors appointed three directors who are independent under the NASDAQ’s standards for audit committee members to serve on its Audit Committee. In addition, the Board of Directors determined that at least one member, John T. Mills, of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 401 of Regulation S-K.

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing and the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited

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financial statements with management, discusses with our independent auditors matters required to be discussed by SAS 114 (Communications with Audit Committees), and makes recommendations to the Board of Directors relating to our audited financial statements.

The Audit Committee is authorized to recommend periodically to the Board of Directors any changes or modifications to its charter that the Audit Committee believes may be required.

Risk Management Committee. The board of directors has established a risk management committee, which consists of three members. The committee responsibilities include identifying and reviewing the risks confronted by the Partnership with respect to its operations and financial condition, establishing limits of risk tolerance with respect to the Partnership’s hedging activities and ensuring adequate property and liability insurance coverage.

Compensation and Nominating Committees. Although we are not required under NASDAQ rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee, as a limited partnership, the Board of Directors of the General Partner has established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers, including the performance standards or other restrictions pertaining to the vesting of any such awards, under our existing Long Term Incentive Plan.

The Board of Directors has also appointed a Nominating Committee to assist the Board and the member of our General Partner by identifying and recommending to the Board of Directors individuals qualified to become Board members, to recommend to the Board director nominees for each committee of the Board and to advise the Board about and recommend to the Board appropriate corporate governance practices. Matters relating to the election of Directors or to Corporate Governance are addressed to and determined by the full Board of Directors.

Meetings of Non-Management Directors and Communication with Directors. As a limited partnership, our General Partner is required to maintain a sufficient number of independent directors (as defined by the NASDAQ rules) for it to satisfy those rules regarding membership of independent directors on the audit committee of its Board of Directors. Our independent directors are required by those rules to meet in executive session at least twice each year. In practice, they meet in executive session at most regularly scheduled meetings of the board. The position of the presiding director at these meetings is rotated among the independent directors. Interested parties may make their concerns known to the independent directors directly and anonymously by writing to the Chairman of the Audit Committee, Regency GP LLC, 2001 Bryan Street, Suite 3700, Dallas, Texas 75201.

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Name	Age	Position with Regency GP LLC
Byron R. Kelley	61	Chairman of the Board, President and Chief Executive Officer
Patrick Giroir	47	Chief Commercial Officer for Gathering and Processing and Transportation segments
Stephen L. Arata	43	Executive Vice President and Chief Financial Officer
Randall H. Dean	53	President and Chief Executive Officer for Contract Compression segment
Dan Fleckman	67	Executive Vice President, Chief Legal, and Administrative Officer and Secretary
Lawrence B. Connors	57	Senior Vice President, Finance and Accounting and Chief Accounting Officer
Christofer D. Rozzell	32	Senior Vice President, Development and Strategic Planning
Dennie W. Dixon	61	Senior Vice President, of Operations for Gathering and Processing and Transportation Segments
Shannon A. Ming	32	Vice President, Investor Relations and Communications
James M. Richter	56	Vice President, Human Resources
Houston C. Ross III	39	Vice President, Financial Analysis and Planning
A. Troy Sturrock	38	Vice President, Controller
Ramon Suarez, Jr.	46	Vice President, Treasurer
Michael J. Bradley(1)(2)(4)	54	Director
James F. Burgoyne(1)	50	Director
Daniel R. Castagnola(5)(6)	42	Director
Rodney L. Gray(2)(3)	56	Director
Paul Halas(4)(6)	52	Director
Mark T. Mellana(4)(5)	44	Director
John T. Mills(2)(3)(5)	61	Director
Brian P. Ward(1)	49	Director

(1) Member of the Executive Committee. Mr. Burgoyne is chairman of this committee.

(2) Member of the Audit Committee. Mr. Mills is chairman of this committee.

(3) Member of Conflicts Committee. Mr. Gray is chairman of this committee.

(4) Member of Compensation Committee. Mr. Mellana is chairman of this committee.

(5) Member of Risk Management Committee. Mr. Mellana is chairman of this committee.

(6) Member of Nominating Committee. Mr. Castagnola is chairman of this committee.

Byron R. Kelley was elected Chairman of the Board of Directors of Regency GP LLC and Regency Gas Services in March 2008. Prior to his appointment, Mr. Kelley spent four years at CenterPoint Energy, which operates two interstate pipeline systems and natural gas gathering and processing systems focused on the mid-continent area. Mr. Kelley served as senior vice president and group president of pipeline and field services, and was responsible for commercial, operational, strategic, regulatory and development aspects of two business units and three lines of business. Preceding his work at CenterPoint, Mr. Kelley served as executive vice president of development, operations and engineering, and as president of El Paso Energy International in Houston, a natural gas pipeline operator. Mr. Kelley also held management and executive positions at other companies in the natural gas pipeline industry. Mr. Kelley is a past chairman and member of the Board of Directors of the Interstate National Gas Association and previously served as one of the association’s representatives on the U.S. Natural Gas Council of America.

Patrick Giroir was elected Chief Commercial Officer for the Gathering & Processing and Transportation Segments of Regency GP LLC November 2008. From May 2008 through November 2008, Mr. Giroir served as Senior Vice President of Strategy and Special Projects of Regency. From October 2003 to May 2008, Mr. Giroir was with CenterPoint Energy’s Pipeline Group which operates two interstate pipeline systems where he held the positions of vice president, Business Development, System Planning and Market Fundamentals and vice president, Strategic Development. In addition, Mr. Giroir is a CPA.

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Stephen L. Arata was elected Executive Vice President and Chief Financial Officer of Regency GP LLC in September 2005. From June 2005 to the present, Mr. Arata served as Executive Vice President and Chief Financial Officer of Regency Gas Services LP and its predecessor. From September 1996 to June 2005, Mr. Arata worked for UBS Investment Bank, covering the power and pipeline sectors; he was Executive Director from 2000 through June 2005. Mr. Arata has extensive experience as a financial consultant, focusing on the energy sector.

Randall H. Dean has served as President and Chief Executive Officer of CDM Resource Management LLC since January 15, 2008. Previously, Mr. Dean served as President and Chief Executive Officer of CDM Resource Management, Ltd. since co-founding it in 1997. Mr. Dean has over twenty years of experience in the natural gas compression industry.

Dan Fleckman was elected Executive Vice President, Chief Legal and Administrative Officer and Secretary of Regency GP LLC in May 2008. Mr. Fleckman has extensive experience in private practice and corporate executive legal positions, representing publicly and privately held companies in corporate finance, corporate governance, mergers and acquisitions, and strategic alliances. Prior to joining Regency, Mr. Fleckman was a partner in the law firm of Vinson & Elkins LLP since June 2000 and previously a partner at the law firm of Andrews Kurth. Mr. Fleckman is a member of the American Bar Association.

Lawrence B. Connors was elected Senior Vice President of Finance and Chief Accounting Officer of Regency GP LLC in February 2008, having served as Vice President, Finance and Chief Accounting Officer since September 2005. From December 2004 to September 2005, Mr. Connors served as Vice President, Finance and Accounting, and Chief Accounting Officer of Regency Gas Services LLC. From June 2003 through November 2004, Mr. Connors served as Controller of Regency Gas Services LLC. Prior to joining the Partnership, Mr. Connors had 24 years of experience in the energy industry in capacities involving finance, accounting, and operations. Mr. Connors is a Certified Public Accountant.

Christofer D. Rozzell was elected Senior Vice President, Development and Strategic Planning of Regency GP LLC in November 2008. From June 2005 to November 2008, Mr. Rozzell served in various roles at Regency GP LLC, most recently as Vice President of Corporate Development. From May 2001 to May 2005, Mr. Rozzell held managerial positions in the strategic planning and enterprise risk groups of TXU Corp., which generates, transmits, and distributes electricity to customers in Texas. Mr. Rozzell has experience in the investment banking industry, focusing on mergers and acquisitions and financings across multiple industries.

Dennie W. Dixon was elected senior vice president of operations for the Gathering and Processing and Transportation segments in January 2009. Prior to working for Regency, Mr. Dixon served as an operations, pipeline and compression consultant for Arledge Gas Gathering, a gas gathering and compression services company with assets in Crockett and Val Verde Counties, Texas. From 1980 to 2004 he held various positions in the natural gas pipeline industry, most recently serving as Director of Liquefied Natural Gas for El Paso Global Gas, where he was involved with the construction and operation of LNG terminal and storage facilities. Dixon retired from El Paso after 33 years of service in 2004.

Shannon A. Ming was elected Vice President, Investor Relations and Communications of Regency GP LLC in February 2008. Mrs. Ming joined Regency GP LLC in April, 2006 as Director of Investor Relations. From August 2001 to March 2006, Mrs. Ming served in various capacities with TXU Corp., which generates, transmits, and distributes electricity to customers in Texas. Mrs. Ming’s responsibilities included managerial positions in strategic planning, product development and marketing.

James M. Richter was elected Vice President, Human Resources in June 2007. From January 2007 to June 2007, Mr. Richter served as the human resources manager at Regency GP LLC. From October 2005 to August

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2006, Mr. Richter worked for USAA, which offers insurance, banking, and investment services, as Senior People Officer. From June 2001 to August 2005, Mr. Richter was employed by Argonaut Group, Inc., an insurance underwriter, as Vice President, Human Resources. Mr. Richter has held various senior management positions at companies in the energy sector.

Houston C. Ross III was elected Vice President of Financial Analysis and Planning of Regency GP LLC in March 2007. From February 2004 until March 2007, Mr. Ross served as Director of Financial Analysis and Planning for Regency Gas Services LP and its predecessor. From February 2003 until February 2004, Mr. Ross worked for Energy, Economic, and Environmental Consultants, Inc., as a Senior Economic Analyst specializing in natural gas royalty litigation support.

A. Troy Sturrock was elected Vice President, Controller of Regency GP LLC in February 2008. From June 2006 to February 2008, Mr. Sturrock served as the Assistant Controller and Director of Financial Reporting and Tax for Regency GP LLC. From January 2004 to June 2006, Mr. Sturrock was associated with the Public Company Accounting Oversight Board, where he was an inspection specialist in the division of registration and inspections. Mr. Sturrock served in various roles at PricewaterhouseCoopers LLP from 1995 to 2004, most recently as a senior manager in the audit practice specializing in the transportation and energy industries. Mr. Sturrock is a Certified Public Accountant.

Ramon Suarez, Jr. was elected Vice President, Treasurer of Regency GP LLC in March 2007. From February 2006 to March 2007, Mr. Suarez was Director of Treasury for Regency GP LLC. Mr. Suarez worked for CompUSA, a computer retailer, as Director of Corporate Finance from March 1999 to December 2005. Mr. Suarez has over 21 years of financial experience.

Michael J. Bradley was elected to the Board of Directors of Regency GP LLC in January 2008. He has been the President and Chief Executive Officer of the Matrix Service Company since November 2006. Prior to joining Matrix Service Company, Mr. Bradley served as President and CEO of DCP Midstream Partners, a midstream MLP and was a member of the board. Mr. Bradley was named Group Vice President of Gathering and Processing for Duke Energy Field Services (DEFS) in 2004 and served as Executive Vice President (DEFS) from 2002 to 2004. Mr. Bradley is a member of the American Society of Civil Engineers. He also serves on the advisory board for the University of Kansas, School of Engineering.

James F. Burgoyne was elected to the Board of Directors of Regency GP LLC in June 2007. Mr. Burgoyne is a Managing Director and global leader of GE Energy Financial Services’ natural resources business, which invests in mid- and downstream oil and gas infrastructure, producing oil, gas and coal reserves, and in a broad range of energy infrastructure in Europe. Mr. Burgoyne has headed this commercial unit within GE Energy Financial Services since it was formed in 2004. Prior to this position, Mr. Burgoyne was a Managing Director with GE Structured Finance’s global energy team, where he was responsible for client development and the origination of business opportunities with US energy companies domestically and internationally. Before joining GE in 1997, Mr. Burgoyne was an Executive Director at SBC Warburg.

Daniel R. Castagnola was elected to the Board of Directors of Regency GP LLC in June 2007. Mr. Castagnola is a Managing Director at GE Energy Financial Services and is responsible for a team of professionals investing in oil and gas infrastructure in North America. Additionally, Mr. Castagnola leads a broad range of energy infrastructure origination efforts, including power, renewable, oil and gas and oil field services investments in Latin America, Mr. Castagnola joined GE in 2002. Prior to joining GE, Mr. Castagnola worked for nine years at an international energy firm and three years at a public accounting firm.

Rodney L. Gray was elected to the Board of Directors of Regency GP LLC on February 22, 2008. Since 2003, Mr. Gray has served as chief financial officer of Colonial Pipeline, an interstate carrier of petroleum products.

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Paul J. Halas was elected to the Board of Directors of Regency GP LLC in June 2007. From June 2006 to the present, Mr. Halas has served as a Managing Director and General Counsel of GE Energy Financial Services. Mr. Halas served as the Senior Vice President Business Development at the National Grid USA Service Company Inc., a provider of natural gas and electricity delivery in the New England/New York region, from May 2005 to June 2006. From August 2003 to May 2005, Mr. Halas served as the President of GridAmerica LLC (Independent Electric Transmission Company, subsidiary of National Grid USA). He also served as Senior VP & General Counsel of GridAmerica LLC from May 2002 to August 2003.

Mark T. Mellana was elected to the Board of Directors of Regency GP LLC in June 2007. Mr. Mellana is a Managing Director at GE Energy Financial Services, which provides financial solutions, such as structured equity, leveraged leasing, partnership project finance and broad based financial solutions, to the global energy industry, and has been with the firm since 1999. Mr. Mellana has held various positions at GE Energy Financial Services and is currently a Managing Director—Operations and Development responsible for equity and development investments. Mr. Mellana serves on a number of boards, including those of Source Gas LLC, a local gas distribution company serving customers in Colorado, Nebraska and Wyoming, and Bobcat Gas Storage LLC, which is developing an underground natural gas storage facility in Landry Parish, Louisiana.

John T. Mills was elected to the Board of Directors of Regency GP LLC in January 2008. Since 2006, Mr. Mills has served on the Board of Directors of and as a member of the audit and compensation committees of CONSOL Energy (NYSE: CNX), the largest producer of high-Btu bituminous coal in the United States. Currently, Mr. Mills also serves as a member of the audit and corporate governance and nominating committees for Cal Dive International Inc. (NYSE: DVR), a marine construction company. Prior to his board appointments, Mills spent 30 years in numerous management and tax-related positions, including his most recent role as chief financial officer for Marathon Oil, a major integrated energy company, until his retirement in 2003.

Brian P. Ward was elected to the Board of Directors of Regency GP LLC in June 2007. Mr. Ward is Managing Director and Chief Risk Officer for GE Energy Financial Services, which provides financial solutions, such as structured equity, leveraged leasing, partnership project finance and broad based financial solutions, to the global energy industry. In this role, Mr. Ward is responsible for underwriting and portfolio risk management for GE Energy Financial Services’ domestic and international assets. Mr. Ward has held this position since January 2004. Immediately prior to joining this unit, Mr. Ward served as Quality Leader for GE Structured Finance, the predecessor business of GE Energy Financial Services. Mr. Ward has worked for GE for more than 25 years.

Reimbursement of Expenses of Our General Partner. Our General Partner will not receive any management fee or other compensation for its management of our partnership. Our General Partner will, however, be reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our General Partner will determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our General Partner may be reimbursed.

Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Exchange Act requires executive officers, directors and persons who beneficially own more than ten percent of a security registered under Section 12 of the Exchange Act to file initial reports of ownership and reports of changes of ownership of such security with the SEC. Copies of such reports are required to be furnished to the issuer. The common units of the Partnership were first registered under Section 12 of the Exchange Act on January 30, 2006. Based solely on a review of reports furnished to our General Partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2008 our General Partner’s officers, directors and greater than 10 percent common unitholders filed all reports they were required to file under Section 16(a).

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Item 11. Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

Overview of Our Executive Compensation Program

This Compensation Discussion and Analysis reviews the compensation policies and decision of our Compensation Committee (the “Committee”) with respect to the following individuals, who are referred to as the “Named Executive Officers,” or “NEOs”:

• Byron R. Kelley, President, Chief Executive Officer and Chairman of the Board

• James W. Hunt, former President, Chief Executive Officer and Chairman of the Board

• Stephen L. Arata, Executive Vice President and Financial Officer

• Dan A. Fleckman, Executive Vice President, Chief Legal Officer, and Secretary

• Randall H. Dean, President and Chief Executive Officer for the Contract Compression Segment

• Richard D. Moncrief, former Executive Vice President and Chief Operating Officer

• Lawrence B. Connors, Senior Vice President, Finance and Accounting and Chief Accounting Officer

Our compensation program is designed to recruit and retain individuals with the highest capacity to develop and grow our business, and to align their compensation with our business’s short- and long-term goals. To do this, our compensation program is made up of the following components: (a) base salary, designed to compensate employees for work performed during the fiscal year; (b) short term-incentive compensation, designed to reward employees for the Partnership’s yearly performance and for individual performance goals achieved during the fiscal year; and (c) equity awards, meant to align NEOs’ interests with the Partnership’s long-term performance.

Role of the Committee and Management

The General Partner is responsible for the management of the Partnership. The Committee is appointed by the Board of Directors of the General Partner to discharge the Board’s responsibilities relating to compensation of the company’s directors and executive officers. The Committee is directly responsible for the General Partner’s compensation programs, which include programs that are designed specifically for our Named Executive Officers.

The Committee is charged, among other things, with the responsibility of reviewing the executive officer compensation policies and practices to ensure (a) adherence to the compensation philosophy and, (b) that the total compensation paid to our executive officers is fair, reasonable and competitive. These compensation programs for executive officers consist of base salary, annual incentive bonus and LTIP awards in the form of equity-based restricted units, as well as other customary employment benefits. Total compensation of executive officers and the relative emphasis of the three main components of annual compensation are reviewed and established on an annual basis by the Committee.

At the beginning of each fiscal year, our Board, based on information and recommendations provided by senior management, approves corporate objectives for the Partnership, including a budget, for the year. These corporate objectives may differ from, and may be greater than, the projections of the anticipated performance of the Partnership provided to the investing public from time to time. The Board also at this time determines the magnitude of the annual incentive bonus pool to be paid to executive officers and employees for the preceding year.

It is the practice of the Committee to meet, in one or more meetings, for several purposes. These include (a) assessing the performance of the CEO and other senior officers with respect to the Partnership results for the

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prior year, (b) reviewing and assessing the personal performance objectives of the senior officers for the preceding year, and (c) determining the amount of the bonus pool approved by the Board to be paid to the executive officers after taking into account both the target bonus levels established for those executive officers at the outset of the preceding year and the foregoing performance factors.

In addition, the Committee, at these meetings and after taking into account both the advice of outside consultants and recommendations of senior management, sets base salary levels and target bonus levels (representing the bonus that may be awarded expressed as a percentage of base salary for the year) for executive officers. The Committee also considers recommendations to be made to the Board regarding awards to executive officers, as well as other employees, under the LTIP for the ensuing fiscal year.

Compensation Philosophy & Objectives

The principal objective of our compensation program is to attract and retain, as executive officers and employees, individuals of demonstrated competence, experience and leadership in our industry and in those professions required by our business and operations who share our business aspirations, values, ethics and culture. A further objective is to provide incentives to and to reward our executive officers and key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.

In setting the compensation programs, we consider the following compensation objectives:

• to create unitholder value through sustainable earnings and cash available for distribution;

• to reward participants for value creation commensurate with competitive industry standards;

• to provide a significant percentage of total compensation that is “at-risk” or variable;

• to encourage significant equity holdings to align the interests of executive officers and key employees with those of unitholders;

• to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and

• to develop a strong linkage between business performance, safety, environmental stewardship, cooperation among business units and employee pay.

We also strive to achieve a fair balance between the compensation rewards that we perceive as necessary to remain competitive in the marketplace and fundamental fairness to our unitholders, taking into account the return on their investment.

In measuring the contributions of our executive officers and the performance of the Partnership, the Committee considers a variety of financial measures, including the non-GAAP financial measures of adjusted EBITDA, cash available for distribution, adjusted segment margin, and adjusted total segment margin, all of which are used by management as key measures of the Partnership’s financial performance. The most important of these are (a) adjusted EBITDA, which we define as net income (loss) plus net interest expense, depreciation and amortization expense, unrealized loss (gain) from risk management activities, non-cash commodity put option expirations and loss on debt refinancing, and (b) cash available for distribution. The Committee also considers total unitholder return, which includes both appreciation in market value of our common units and the amount of distributions paid with respect to all our outstanding units. In addition, the Committee takes into account a variety of factors related to individual performance. The Committee believes that the measures outlined above best define the performance of the Partnership.

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Market Analysis

In 2008, to ensure that our compensation practices are competitive, the Committee retained BDO Seidman, LLP to provide a total compensation analysis for executive officers and certain key employees. The Committee selected a peer group that includes twenty publicly-traded limited partnerships listed below, that are in the mid-stream market of the oil and gas industry. In selecting this peer group, we considered those of our competitors that are of a size similar to our own, measured by market capitalization. Our market capitalization falls in the median range of the peer group. Our peer group consists of the following group of companies:

Atlas Pipeline Partnerships LP	Holly Energy Partners LP
Boardwalk Pipeline Partners, LP	Magellan Midstream Partners LP
Buckeye Partners LP	Markwest Energy Partners LP
Copano Energy LLC	Martin Midstream Partners LP
Crosstex Energy LP	Nustar Energy LP
DCP Midstream Partners LP	Plains All American Pipeline LP
Eagle Rock Energy Partners LP	Quicksilver Gas Services LP
Energy Transfer Partners LP	Sunoco Logistics Partners LP
Enterprise Products Partners LP	Targa Resources Partners LP
Hiland Partners LP	Teppco Partners LP

In addition to our peer group, we also rely on the expertise of our compensation consultant, BDO Seidman, who uses confidential and proprietary surveys in order to obtain a more complete picture of the overall compensation environment.

When considering the data, the Committee generally targets each component of compensation to the median range by reference to persons with similar duties at our peer group companies. The Committee also seeks to reward our executive officers when the Partnership achieves its stretch performance goals by providing compensation that is in the upper quartile of our peer group. However, actual compensation decisions for individual officers are the result of the Committee’s subjective analysis of a number of factors, including the individual officer’s experience, skills or tenure with us, changes to the individual’s position, or trends in compensation practices within our peer group or industry. Each executive’s current and prior compensation is considered in setting future compensation. The amount of each executive’s current compensation is considered as a base against which the Committee makes determinations as to whether increases are necessary to retain the executive in light of competition or in order to provide continuing performance incentives. Thus, the Committee’s determinations regarding compensation are the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary. The Committee may use its discretion to adjust any of the components of compensation to achieve our goal of recruiting, promoting and retaining individuals with the skills necessary to execute our business strategy and develop and grow our business.

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Elements of the Compensation Programs

Overall, the executive compensation programs are designed to be consistent with the philosophy and objectives set forth above. The principal elements of our executive compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.

Element	Characteristics	Purpose
Base salary	Fixed annual cash compensation; executive officers are eligible for periodic increases in base salary based on performance; targeted over time to approximate the 50th percentile in pay level.	Keep our annual compensation competitive with the defined market for skills and experience necessary to execute the Partnership’s business.
Annual incentive bonus	Performance-based annual cash incentive earned based on corporate objectives and individual performance against target performance levels; targeted to approximate the 50th percentile.	Align performance to the corporate objectives that drive the Partnership’s business and reward executive officers for achievement of both corporate and individual performance objectives. Amounts earned for achievement of target performance levels are designed to provide competitive total direct compensation; potential for lesser or greater amounts are intended to motivate executives to achieve or exceed our financial and operational goals; no rewards are paid if performance goals are not met.
Equity based awards (restricted units)	Performance-based equity awards granted at the discretion of the Committee. Awards are based on performance of the Partnership and competitive practices at peer companies. Grants typically vest ratably over four years and are eligible for distribution payments.	Align interest of executive officers with unitholders; motivate and reward executive officers to increase unitholder value over the long term. Ratable vesting over a four year period will facilitate retention of executive officers.
Equity based awards (Class C Units)	Class C units are a separate class of securities representing an economic interest in our General Partner. These units are structured as management incentive equity and vest based on performance attributable to achieving certain levels of distributable cash on a per unit basis.	Align the interest of executive officers with unitholders and reward executives for value creation associated with the Partnership.
Retirement savings plan	Tax-deferred 401(k) plan in which all employees can choose to defer compensation for retirement up to IRS imposed limits ($15,500 for 2008) The Partnership matches $1 for $1 up to 6 percent of eligible compensation.	Provide employees with the opportunity to save for their future retirement.
Health & welfare benefits	Health & welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for all regular full-time employees.	Provides benefits to meet the health and wellness needs of employees and their families.

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Compensation Components and Analysis

Base Salary

Design. Base salaries are targeted at market median levels, although each executive officer may have a base salary above or below the median of the market. Actual individual salary amounts are not objectively determined, but instead reflect the Committee’s subjective analysis of a number of factors, including the individual officer’s experience, skills or tenure with the company, changes to the individual’s position within the company, or trends in compensation practices within our peer group or industry. In addition, the Committee also carefully considered the input and recommendations of the CEO when evaluating factors relative to the other executive officers, or, in the case of the CEO, the chairman of the Committee.

2008 Fiscal Year Results. Effective as of March 31, 2008, the Committee made the following decisions with respect to salary adjustments:

• Mr. Hunt: no salary increase, due to his resignation;

• Messrs. Arata and Connors: base salaries were increased to $275,000 (10 percent) and $190,000 (5 percent), respectively. Their salary increases matched or lagged the marketplace;

• Mr. Moncrief: base salary was increased to $325,000 (18 percent). His salary increase reflected his promotion to Chief Operations Officer;

• Messrs. Kelley, Fleckman and Dean: as new hires in 2008, received base salaries of $475,000, $225,000 and $316,900, respectively. Compensation decisions for Messrs. Kelley, Fleckman, and Dean were the result of negotiations in a competitive environment. In making base salary decisions for them, we took into account the position that each would fill, the potential value that each would provide to the Partnership, the compensation that each earned in his prior employment, and our desire to incentivize them to join our Partnership.

While our stated goal is to approximate the salaries of the 50th percentile of our peer group of companies, we believe that it is important, in some cases, to deviate from in order to attract the best talent for critical positions within our company. As a result, the base salaries of Messrs. Kelley and Dean are closer to the 75th percentile of base salary compensation that our peer companies pay to executives with similar positions and responsibilities.

Changes for Fiscal Year 2009. At its meeting in February 2009, the Committee discussed salary data for our comparator group, our annual performance targets for individual officers, and general economic conditions and challenges facing the Company in this fiscal year. The Committee decided to defer base salary considerations for the NEOs until mid-year.

Annual Incentive Bonuses

Design. Annual incentive bonuses are targeted at market median levels. If target goals are achieved, each Named Executive Officer is eligible to receive an annual bonus opportunity ranging from 75 percent to 100 percent of his base salary. To arrive at a payout amount, 80 percent of bonus opportunity is based on the achievement of corporate performance goals and 20 percent is based on the Committee’s subjective evaluation of each Named Executive Officer’s individual performance. However, the determination of any actual amounts paid out under this plan is subject to the Committee’s discretion.

For 2008, the Committee established the following corporate performance objectives:

• Adjusted EBITDA—defined as net income (loss) plus net interest expense, depreciation and amortization expense, unrealized loss (gain) from risk management activities, non-cash commodity put option expirations, and loss on debt refinancing;

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• Segment Adjusted EBITDA—depending on the Named Executive Officer, achievement of Segment Adjusted EBITDA is tied to performance of either our gathering, processing and transportation segments or contract compression segment; and

• Cash distributed on a per unit basis.

Each of these performance metrics is equally weighted and is subject to a “threshold,” “target” and “stretch” performance goal. If threshold performance is achieved, no portion of the bonus opportunity that is attributable to company performance will be paid. If target performance is achieved for each metric, then 80 percent of the bonus opportunity may be paid. If stretch performance is achieved, then the Committee has the discretion to apply a 3x multiplier to the target payout amount, resulting in the potential to be paid up to 240 percent of bonus opportunity. Annual incentive bonuses are prorated if actual performance falls between the defined threshold and stretch corporate performance targets. For 2008, the corporate performance targets were as follows:

Performance Metric	Threshold		Target		Stretch
Adjusted EBITDA (millions)	$	230	$	242	$	262
Segment Adjusted EBITDA
Gathering/Processing/Transportation (millions)1		154		165		185
Compression (millions)2		51.6		55.7		62.5
Per Unit Cash Distributions		1.64		1.74		1.90

1 In evaluating the bonus opportunity for Segment Adjusted EBITDA performance, the bonus opportunity for Messrs. Kelley, Arata, Fleckman and Connors is calculated only with regard to the Gathering and Processing and Transportation Segments. Segment Adjusted EBITDA excludes the operating results of FrontStreet.

2 In evaluating the bonus opportunity for Segment Adjusted EBITDA performance, the bonus opportunity for Mr. Dean is calculated only with regard to the Contract Compression Segment.

For 2008, approximately 20 percent of the bonus opportunity is dependent on the Committee’s subjective assessment of each Named Executive Officer’s individual performance. The Committee’s evaluation of individual performance takes into account a range of factors, that may vary for individual officers, and may include effective leadership, teamwork, customer focus, safety, environmental stewardship, the development of individuals responsible to the applicable officer, and the officer’s role within the Partnership. Based on the CEO’s review of each Named Executive Officer’s performance, each officer is then assigned a numerical performance rating. However, any amounts awarded based on individual performance are subject to the Committee’s discretion.

The following table describes each Named Executive Officer’s bonus opportunity, calculated as a percentage of base salary.

	2008 Annual Incentive Bonus Opportunity as a % of Salary
Named Executive Officer	Threshold Performance		Target Performance		Maximum Performance
Byron R. Kelley	0	%	100	%	3 x Target Performance Award
James W. Hunt	Ineligible		Ineligible		Ineligible
Stephen L. Arata	0	%	75	%	3 x Target Performance Award
Dan A. Fleckman	0	%	75	%	3 x Target Performance Award
Randall H. Dean	0	%	100	%	3 x Target Performance Award
Lawrence B. Connors	0	%	75	%	3 x Target Performance Award
Richard Moncrief	Ineligible		Ineligible		Ineligible

The Committee, in its sole authority, retains the right to apply an additional discretionary multiplier to any or all bonus awards. This discretionary multiplier ranges from zero to two times eligible bonus award and allows the Committee broader discretion in achieving pay for performance objectives. This discretionary multiplier is

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meant to reward extraordinary corporate performance or extraordinary individual contributions to the achievement of corporate or individual performance targets. In 2008, the Committee chose to apply a discretionary multiplier to reduce bonus awards to approximate target levels.

Fiscal Year 2008 Results. The following chart shows our 2008 actual financial results:

Performance Metric	Financial Results
Adjusted EBITDA (millions)	$	254.5
Segment Adjusted EBITDA
Gathering/Processing/Transportation (millions)(1)	$	175.8
Contract Compression (millions)(2)	$	58.7
Per Unit Cash Distributions	$	1.755

(1) In evaluating the bonus opportunity for Segment Adjusted EBITDA performance, the bonus opportunity for Messrs. Kelley, Arata, Fleckman and Connors is calculated only with regard to the Gathering and Processing and Transportation Segments. Segment Adjusted EBITDA excludes the operating results of FrontStreet.

(2) In evaluating the bonus opportunity for Segment Adjusted EBITDA performance, the bonus opportunity for Mr. Dean is calculated only with regard to the Contract Compression Segment.

The Partnership exceeded the corporate performance target for each performance metric, which created a bonus opportunity of 180 percent of base salary for Messrs. Kelly, Arata, Fleckman and Connors, and a bonus opportunity of 173 percent for Mr. Dean. However, as a result of current economic conditions and the Partnership’s desire to reduce cash outlays and limit expenses, including compensation expenses, the Committee exercised its discretion to limit bonus awards to approximate target levels.

Named Executive Officer	Annual Incentive Bonus Award as a% of Salary
Byron R. Kelley(1)	84	%
James W. Hunt	N/A
Stephen L. Arata(2)	76	%
Dan A. Fleckman(3)	50	%
Randall H. Dean	100	%
Lawrence B. Connors(2)	74	%
Richard Moncrief	N/A

(1) Mr. Kelley’s annual bonus award was determined in compliance with the terms of his employment contract, which guaranteed him a $400,000 bonus.

(2) The Committee, in its discretion, made slight adjustments to Mr. Arata’s and Mr. Connors’ bonus awards.

(3) The Committee prorated Mr. Fleckman’s bonus award to account for his May 1, 2008 start date.

Changes for Fiscal Year 2009.

As of the time of filing of this Compensation Discussion and Analysis, the Committee has not approved any changes to the annual incentive compensation program for fiscal year 2009. If the Committee makes any material changes to the annual incentive compensation program, those changes will be disclosed on a Form 8-K.

Equity-Based Awards

Design. The LTIP was adopted at the time of the initial public offering of the Partnership in 2006. In adopting the LTIP, our Board of Directors recognized that it needed a source of equity to attract new members to the management team, as well as to provide an equity incentive to other key employees. We believe the LTIP promotes a long-term focus on results and aligns employee and unitholder interests.

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Equity awards are granted under our LTIP and are targeted at median market levels, though awards in a particular year are a result of a number of factors, including the availability of a pool of equity units from which to make awards. In reviewing equity-based awards to executive officers, including options, restricted units, phantom units and distribution rights, the Committee gives consideration to the number of such awards already held by each individual. Equity-based awards may be awarded to executive officers at the commencement of their employment, annually on meeting corporate and individual objectives, and from time to time by the Committee based on regular assessments of the compensation levels of comparable companies.

Restricted Units. The only awards made under the LTIP in 2008 were restricted units. Restricted units so awarded may not be sold until vested, and unvested restricted units will be forfeited at the time the holder terminates employment. In general, restricted units awarded under our LTIP vest as to one-fourth of the award on each of the first four anniversaries of the date of the award. Restricted units participate in distributions on the same basis as other common units.

Class C Units. Class C Units are structured as management incentive equity and the vesting of these units will entitle the holders to participate in quarterly distributions or incentive distributions by the Partnership attributable to the interests in our General Partner. The Class C Units, as a whole, will participate in those distributions based on the level of distributable cash per unit produced by the Partnership (without regard to incentive distribution rights): At the annual level of less than $2.50 per common unit, no participation; $2.50 - $2.74, two percent of the distributions received; $2.75 - $2.99, five percent of the distributions received; and $3.00 or more, ten percent of the distributions received. The Class C Units vest at the time a level of participation is achieved and vest at that level (until another level is achieved). If the employment of a holder of Class C Units is terminated for any reason, including death or disability, any unvested Class C Units will be forfeited to GE EFS and will be available for reissuance.

The receipt of any distributions with respect to the Class C Units is subject to contingencies relating to the levels of cash available for distribution by the Partnership on the common units and to the continued employment of the holders of the units. The Class C Units are not yet entitled to any distributions and none have vested. Accordingly, no value has been assigned to the Class C Units and none has been included in the summary compensation table.

2008 Fiscal Year Results. As a result of the availability of a limited number of units remaining available for grant under our LTIP, we made very few grants of equity awards to our employees during 2008. With respect to our named executive officers, we granted equity only to Messrs. Kelley and Fleckman in connection with our employment of them. Mr. Kelley was granted (a) 106,300 restricted units, with 56,300 units vesting in equal increments on the second and fourth anniversary of the grant date of the award and the remaining 50,000 units vesting ratably over four years and (b) 85 Class C Units representing 10.7 percent of the pool of such units. Mr. Fleckman was granted (a) 75,000 restricted units, which vest ratably over 4 years and (b) 50 Class C Units representing 6.3 percent of the pool of such units. While our goal is to target the market median of our peer group for equity compensation, we believe that it is appropriate to deviate from that range of compensation to recruit key individuals and to align their interests with long-term interests of the Partnership. We recognized that equity compensation would be a significant factor in negotiations with these individuals who were leaving behind significant compensation packages at their prior places of employment. These equity awards were important tools for compensating our new hires for the value they were leaving behind. These awards placed the Partnership in the range of the 75th percentile of our peer companies and we believe they were appropriate in light of the Partnership’s investment in individuals that we believe are key to our long-term strategy.

Changes for Fiscal Year 2009. At its meeting in February 2009, the Committee did not make any material changes to long-term compensation for fiscal year 2009.

Deferred Compensation

Among our peer group of companies, tax-deferred 401(k) plans are a common way that companies assist employees in preparing for retirement. We provide our eligible officers and employees with an opportunity to

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participate in our tax-deferred 401(k) savings plan. The plan allows executive officers to defer compensation for retirement up to IRS imposed limits ($15,500 for 2008). The Partnership matches $1 for $1 up to 6 percent of eligible compensation. Decisions regarding this element of compensation do not impact any other element of compensation.

Perquisites

Perquisites are not a significant factor in our compensation structure. During salary negotiations, the Partnership agreed to provide Mr. Kelley with a $4,500 per month housing allowance until Mr. Kelley elects to relocate his family to Dallas, Texas.

Employment Agreements, Severance Benefits and Change in Control Provisions

We maintain employment and other compensatory agreements with some of our corporate officers for a variety of reasons, including the fact that employment agreements can be an important recruiting tool in the market in which we compete for talent. Certain provisions in these agreements, such as confidentiality, non-solicitation, and non-compete clauses, protect the Partnership and its unitholders after the termination of the employment relationship. We believe that it is appropriate to compensate former employees for these post-termination agreements, and that compensation helps to enhance the enforceability of these arrangements. In particular, we entered into a consulting services agreement with Mr. Hunt in connection with his retirement. In exchange for management consulting and advisory services from April 1 to December 31, 2008, we agreed to pay Mr. Hunt $33,500 per calendar month, the equivalent of his annualized base salary on a monthly basis. In connection with Mr. Moncrief’s resignation and his agreement to provide us with management consulting and advisory services, we entered into a resignation and release agreement with him under which we paid him a lump sum payment of $262,250, the amount of which was determined through negotiations. These agreements are described in more detail elsewhere in this document. Please read “Executive Compensation—Potential Payments Upon a Termination or Change in Control.

Recoupment Policy

We currently do not have a recovery policy applicable to annual incentive bonuses or equity awards. The Committee will continue to evaluate the need to adopt such a policy, in light of current legislative policies, economic and market conditions.

Class B Units

In conjunction with the GE EFS’s Acquisition in June 2007, certain members of our management team received Class B membership interests in the Company. The Committee considers the Class B interests to be investments, rather than compensation, because management purchased the Class B interests with cash or through an exchange of membership interests in the pre-acquisition Company. Consequently, the values attributable to the Class B units and any distributions made with respect to those units are not included in the summary compensation table.

Committee Report

We have reviewed and discussed with management certain compensation discussion and analysis provisions to be included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934 (the “Annual Report”). Based on those reviews and discussions, we recommend to the board of Directors of the General Partner that the compensation discussion and analysis be included in the Annual Report.

Compensation Committee

Mark T. Mellana, Chairman

Michael J. Bradley

Paul J. Halas

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COMPENSATION TABLES AND NARRATIVES

Summary Compensation Table for 2008

Name and Principal Position	Year	Salary ($)	Stock Awards ($)(2)	Option Awards ($)(2)	Non Equity Incentive Plan Compensation ($)	All Other Compensation ($)(4)(5)		Total ($)
Byron R. Kelley(1) President, Chief Executive Officer and Chairman of the Board	2008	356,250	249,118	—	400,000	72,189	(3)	1,077,557
	2007	—	—	—	—	—		—
	2006	—	—	—	—	—		—
James W. Hunt(6) Former President, Chief Executive Officer and Chairman of the Board	2008	100,000	—	—	—	—		100,000
	2007	400,000	—	79,954	—	9,334		489,288
	2006	386,667	—	35,046	10,000	7,600		439,313
Stephen L. Arata Executive Vice President and Chief Financial Officer	2008	268,750	—	—	208,200	10,029		486,979
	2007	250,000	—	27,987	127,875	10,324		416,186
	2006	245,833	—	12,266	6,250	6,250		270,599
Dan A. Fleckman(1) Chief Legal Officer, Executive Vice President and Secretary	2008	150,000	339,578	—	112,800	6,012		608,390
	2007	—	—	—	—	—		—
	2006	—	—	—	—	—		—
Randall H. Dean(1) President and Chief Executive for the Contract Compression Segment	2008	303,696	—	—	316,000	16,922		636,618
	2007	—	—	—	—	—		—
	2006	—	—	—	—	—		—
Lawrence B. Connors Chief Accounting Officer and Senior Vice President	2008	187,500	79,166	—	140,500	8,792		415,959
	2007	180,000	40,665	12,004	55,800	8,450		296,919
	2006	176,000	—	5,246	4,500	750		186,496
Richard D. Moncrief(6) Former Executive Vice President and Chief Operating Officer	2008	271,875	—	—	—	272,591		544,466
	2007	237,500	1,814,660	43,584	187,550	50,115		2,333,409
	2006	145,513	269,840	13,916	5,000	1,500		435,769

(1) The amount under “Salary” reflects a pro rata portion of salary for Messrs. Kelley, Fleckman, and Dean, who began employment with the Partnership on April 1, 2008, May 1, 2008, and January 15, 2008, respectively.

(2) The amount included in the “Stock Awards” and “Option Awards” columns reflect the dollar amount of compensation expense recognized with respect to these in accordance with SFAS No. 123R for the years ended December 31, 2008, 2007 and 2006. The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis-Components of Compensation-Equity Based Awards.” No compensation is attributable to Class C units. The material terms of our Class C units are described in “Compensation Components and Analysis, Equity-Based Awards, Class C Units.”

(3) The amount includes payments of $41,539 and $15,851 for living and moving expenses, respectively.

(4) The amount includes the Partnership contribution on behalf of the named executive officer to its 401(k) plan. The contribution basis for our executives is the same basis as all other employees of the Partnership.

(5) The Partnership did not provide perquisites or other personal benefits to any named executive officer exceeding $10,000.

(6) Messrs. Hunt and Moncrief each resigned from his position on April 1, 2008 and November 14, 2008, respectively.

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Grant of Plan Based Awards

The following table provides information concerning each grant to our NEOs in the year ended December 31, 2008.

Grants of Plan-Based Awards

For the Year Ended December 31, 2008

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stock or Units (#)	Grant Date Fair Value of Stock Awards ($)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)
Byron R. Kelley	3/17/2008	0	475,000	1,235,000	106,300	2,825,454
James W. Hunt	—	—	—	—	—	—
Stephen L. Arata	—	0	206,500	536,900	—	—
Dan A. Fleckman	5/01/2008	0	168,750	438,750	75,000	2,025,000
Randall H. Dean	—	0	316,900	823,940	—	—
Lawrence B. Connors	—	0	142,500	370,500	—	—
Richard D. Moncrief	—	—	—	—	—	—

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

The following is a discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table and the Grants of Plan-Based Awards Table for 2008.

Employment, Incentive Compensation and Non-Compete Agreements

Byron R. Kelley: Effective as of April 1, 2008, Regency GP LLC entered into an employment agreement with Byron R. Kelly. The agreement will terminate on April 1, 2010, subject to additional one-year extensions until either the Partnership or Mr. Kelley gives at least one-year’s written prior notice of non-renewal. Mr. Kelley’s annual base salary is $475,000, subject to increases by the Committee and a monthly living allowance of $4,500. Under the employment agreement, Mr. Kelley is eligible to participate in the annual bonus plan, and will have a target bonus equal to his annual base salary; provided that Mr. Kelley will receive a minimum bonus for 2008 of $400,000 and for 2009 of $200,000 regardless of any performance criteria achieved. The agreement also entitled Mr. Kelley to a grant of 106,300 restricted units, the terms of which are discussed above in “Compensation Discussion and Analysis – Compensation Components and Analysis – Equity-Based Awards – 2008 Fiscal Year Results.”

Mr. Kelley was also awarded 85 Class C Units of GP Acquirer, an indirect subsidiary of GECC. The Class C Units are not yet entitled to any distributions. Please read the section entitled “Compensation Discussion and Analysis – Compensation Components and Analysis – Equity-Based Awards – Class C Units” for a description of the material terms of the Class C Units.

James W. Hunt: At the time of his employment by Regency Gas Services LLC on December 1, 2004, James W. Hunt, President and Chief Executive Officer, entered into an employment agreement with Regency Gas Services LLC. The agreement provided for a term of three years, a base salary of $240,000, participation by Mr. Hunt in the LTIP and other benefit plans adopted by the employer. This agreement was assigned by Regency Gas Services LLC to the Partnership.

In conjunction with his resignation, Mr. Hunt entered into a consulting services agreement dated April 1, 2008. The agreement specified that Mr. Hunt would perform any and all management consulting and advisory services from time to time through the period of December 31, 2008. Mr. Hunt was paid a rate of $33,500 per

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calendar month, commencing with the month of April 2008. The agreement also effectively terminated Mr. Hunt’s employment agreement.

Dan A. Fleckman: On May 1, 2008. Regency GP LLC entered into a severance agreement with Mr. Fleckman. The term of the agreement extends through May 1, 2011. For additional information regarding the material terms of this agreement, please see the narrative below entitled “Potential Payments Upon a Termination or Change in Control.”

Randall H. Dean: On December 2, 2008, we amended and restated our employment agreement with Randall Dean. The agreement extends through January 15, 2011, provides for a base salary of $316,900 per year, subject to increases by the Committee, and allows Mr. Dean to be eligible for an annual performance bonus of up to 100 percent of his then-current annual base salary. Mr. Dean is also eligible to receive equity grants awarded to him under the LTIP in the Committe’s discretion, and to participate in any benefit plans. Mr. Dean has agreed to keep certain information confidential as part of the agreement, and has also agreed to certain non-compete and non-solicitation provisions, should his employment be terminated. For additional information regarding provisions applicable upon a termination or a change of control, please see the narrative below entitled “Potential Payments Upon a Termination or Change in Control.”

Richard D. Moncrief: The Partnership entered into a resignation and release agreement with Mr. Moncrief effective as of December 12, 2008. In consideration for the releases and covenants contained in the agreement, Mr. Moncrief received a payment of $262,500 on January 21, 2009.

Restricted Units

The awards reported in the “Stock Awards” column of the Summary Compensation Table reflect awards of restricted units. Each restricted unit represents a contractual right to receive one common unit. The awards of restricted stock units granted to our Named Executive Officers during fiscal 2008 are generally subject to a four-year vesting schedule subject to such Named Executive Officer’s continued employment with us through the vesting date. The Named Executive Officer does not have the right to sell or dispose of unvested restricted units, and unvested units are forfeited at the time the holder terminates employment. Restricted units participate in distributions on the same basis as other common units.

Options

No options were granted during fiscal 2008. Each option granted prior to fiscal 2008 and reported in the “Option Awards” column of the table above was granted with a per-share exercise price equal to the fair market value of a common unit on the grant date. For these purposes, and in accordance with the terms of the LTIP and our option grant practices, the fair market value is equal to the closing price of a common unit on the applicable grant date.

All Other Compensation

Please see the “Compensation Discussion and Analysis” above for a discussion of any perquisites paid to our Named Executive Officers, and the section below entitled “Potential Payments Upon a Termination or Change in Control” for a discussion of payments made upon resignation.

Description of Plan-Based Awards

The terms of the “non-equity incentive plan” awards reflected in the Summary Compensation Table and in Columns (c) through (e) of the Grants of Plan-Based Awards Table are described in the “Compensation Discussion and Analysis” above.

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Salary and Cash Incentive Awards in Proportion to Total Compensation

The following table sets forth the percentage of each Named Executive Officer’s total compensation that we paid in the form of salary and bonus.

Name	Percentage of Total Compensation
Byron R. Kelley	70	%
James W. Hunt	—
Stephen L. Arata	98	%
Dan A. Fleckman	43	%
Randall H. Dean	97	%
Lawrence B. Connors	79	%
Richard D. Moncrief	—

Outstanding Equity Awards at December 31, 2008

The following table provides information concerning common units that have not vested for our Named Executive Officers.

	Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)(1)		Market Value of Shares or Units of Stock That Have Not Vested ($)(2)
Byron R. Kelley	106,300	(1)	855,715
James W. Hunt	—		—
Stephen L. Arata	—		—
Dan A. Fleckman	75,000	(3)	603,750
Randall H. Dean	—		—
Lawrence B. Connors	7,500		60,375
Richard D. Moncrief(4)	—		—

(1) The forfeiture restrictions on unvested restricted unit awards will lapse as follows: 23,150 on April 1, 2010; 23,150 on April 1, 2012; and the remaining 50,000 units on each of the four anniversaries of the April 1, 2008 grant date.

(2) Based on the closing price of $8.05 per common unit as of December 31, 2008.

(3) The forfeiture restrictions on unvested restricted unit awards will lapse as follows: 25 percent on each of the four anniversaries of the May 1st grant date.

The following table provides information relating to the exercise of unit option awards during 2008 on an aggregated basis for each of our Named Executive Officers. No forfeiture restrictions lapsed with respect to restricted unit awards during 2008.

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Option Exercises and Stock Vested for the Year Ended December 31, 2008

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting	Value Realized on Vesting ($)
Byron R. Kelley	—	—	—	—
James W. Hunt	100,000	679,000	—	—
Stephen L. Arata	—	—	—	—
Dan A. Fleckman	—	—	—	—
Randall H. Dean	—	—	—	—
Lawrence B. Connors	—	—	2,500	61,700
Richard D. Moncrief	—	—	—	—

Potential Payments upon a Termination or Change in Control

We maintain individual employment and severance agreements with certain of our NEOs that could provide for potential severance payments upon a termination of employment. Our LTIP, subject to alternative provisions provided in individual award agreements, also generally provides for the potential acceleration of all unvested outstanding equity awards upon a change in control.

The employment agreement we maintain with Mr. Kelley provided for an initial grant of 106,300 restricted units to be governed by the terms of our LTIP, and these units will receive accelerated vesting upon a change in control as described below. In the event that Mr. Kelley is terminated without “Cause,” or he terminates for “Good Reason,” we are obligated to provide a lump sum in cash within 10 days of the termination date equal to any earned but unpaid salary and bonus, accrued vacation and unreimbursed expenses (“Accrued Obligations”). We will also pay him a lump sum within a 60-day period following the date of termination an amount equal to four times his annual base salary. If we decide to waive his non-compete provisions (which extend for two years following a termination of employment), however, we may reduce this severance payment to two times his annual base salary. If we terminate Mr. Kelley without Cause or he terminates for Good Reason three months preceding or within the two-year period immediately following a “Change in Control,” we will pay Mr. Kelley an amount that is equal to four times his annual base salary, whether or not we have waived his non-compete provisions (whether utilizing the multiplying factor of two or four, such payment will be referred to as the “CEO Severance Payment”). Mr. Kelley will also receive COBRA continuation coverage at the same monthly premium charged to an active employee for similar coverage during the twelve-month period following such a termination of employment without Cause or for Good Reason. Mr. Kelley will not receive the CEO Severance Payment before the first day of the seventh month following his termination from service, however, in the event that he is considered a “specified employee” pursuant to section 409A of the Code. He will also be required to sign a full release before receiving the CEO Severance Payment or the COBRA continuation coverage.

In the event of Mr. Kelley’s termination of employment due to his death or “Disability” he, or his representatives, will receive the Accrued Obligations in a lump sum within 10 days of the date of termination. If Mr. Kelley begins receiving benefits under our long-term disability plan following a Disability termination, we will provide a monthly payment to Mr. Kelley until he reaches age 65 equaling the difference between the disability payments he receives from such plan, and the disability payments he would have received from the plan if the plan did not limit payments to 60 percent of his annual base salary.

A Good Reason termination may occur upon a material reduction in Mr. Kelley’s authority or duties, a reduction in his base salary, our material breach of his employment agreement, or our requirement that he relocate to an office outside of Texas. Mr. Kelley’s termination for “Cause” shall mean: (i) a material nonperformance of his duties; (ii) his commission of fraud upon, or willful misconduct with respect to, us or any of our affiliates; (iii) a material breach of confidentiality, or any breach of the non-compete, non-solicitation or

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prior commitment provisions within his employment agreement; (iv) a felony conviction or a misdemeanor involving moral turpitude; (v) any conduct of Mr. Kelley that causes us public disgrace or disrepute; or (vi) failure to comply with a directive from our Board of Directors. “Disability” is defined as Mr. Kelley’s inability to perform his duties, with or without reasonable accommodation, due to a mental or physical incapacity for a period of time as defined in our long-term disability plan, and in the event that no such plan exists at the time that Mr. Kelley’s Disability must be determined, for a period of 180 consecutive days. A Change in Control under Mr. Kelley’s employment agreement will occur only on the date that the GE EFS Group (meaning Regency GP Acquirer L.P., Regency LP Acquirer LP and any person that controls these entities or their respective directors, officers, shareholders, members, employees or management committees) ceases to be the beneficial owner of at least 50% of the combined voting power of our outstanding voting securities.

The Consulting Services Agreement we entered into on April 1, 2008 with Mr. Hunt served to terminate the employment agreement we previously maintained with Mr. Hunt, and thus terminated any potential severance or change in control payments contained within that agreement. Mr. Hunt remained subject to the confidentiality provisions and the non-compete and non-solicitation restrictions of that original employment agreement, however, until January 1, 2009.

The Resignation and Release Agreement we entered into on December 12, 2008 with Mr. Moncrief provided for a one-time payment of $262,500 (the “Resignation Payment”), as well as for six months of the monthly premium for continued medical coverage.

The employment agreement we maintain with Randall Dean provides for severance payments in the event that we terminate him without “Cause” or he terminates his employment for “Good Reason.” Mr. Dean would receive a payment equal to one year’s salary, a pro-rated bonus payment calculated by assuming maximum targets were met for the year in which the termination occurs, continuation of medical coverage for thirty-six months, and all outstanding equity awards will become vested. Cash payments will be paid within seventy-four days following his termination of employment, unless he is considered a “specified employee” pursuant to section 409A of the Code, in which case payments will be delayed for a period of six months following the date of termination. Mr. Dean will be subject to a non-compete and non-solicitation period of three years following his termination of employment for any reason.

Good Reason termination events for Mr. Dean include: (i) a material change in Mr. Dean’s duties, (ii) our failure to cure a material breach of the employment agreement, (iii) any changes in our key executive personnel or a material adverse change in their terms of employment, (iv) a material change in the business method by which we perform contract compression services, (v) the cessation of our quarterly bonus program, or (vi) a relocation of our corporate office. In the event that Mr. Dean terminates his employment as a result of items (iii) through (vi) above, however, he will not receive the portion of his severance that relates to a payment equaling one year’s salary. Mr. Dean’s employment agreement provides for a termination for Cause upon: (a) his conviction of a felony, (b) his breach of the confidentiality or non-compete obligations, (c) a court determination that Mr. Dean has breached his fiduciary duty of loyalty, due care or good faith, (d) willful or gross neglect of his duties, (e) committing an act of fraud against us, (f) misappropriating our funds or property, or (g) acting in a manner that competes or materially injures us, or his material breach of his employment agreement.

The severance agreement we maintain with Mr. Fleckman provides for a severance payment if Mr. Fleckman is terminated without “Cause,” or if Mr. Fleckman terminates for “Good Reason,” before May 1, 2011. This severance payment will initially be in the amount of $900,000 reduced by the sum of: (i) the amount of salary he receives (or is due) up until the date of his termination of employment, and (ii) the bonus he either received the previous year, or if no such bonus was due, the bonus he should have received for the year in which the termination occurs (the “Severance Payment”). We will also pay for the company portion of the medical, dental and vision insurance that is comparable to the coverage we maintain for similarly situated employees for eighteen months (less the time, if any, by which his employment with us exceeded eighteen months on the date of termination). Mr. Fleckman will also be obligated to sign a release in our favor before receiving any severance

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payments. For purposes of Mr. Fleckman’s severance agreement, the term Cause shall mean: (i) the misappropriation of funds or an act of fraud, (ii) the conviction of a felony, (iii) willful misconduct or gross negligence, (iv) a material violation of our code of conduct or workplace harassment policy, (v) habitual insobriety or substance abuse, or (vi) becoming subject to an order obtained or issued by the SEC for a securities law violation involving fraud. A Good Reason termination is defined as Mr. Fleckman’s voluntary termination following our assignment of duties inconsistent with his position, a reduction in his base salary, or a termination or material reduction of a benefit under either our or any of our affiliates’ benefit plans.

Messrs. Arata and Connors do not have individual agreements that provide for severance or change in control payments.

The restricted units awarded under the LTIP to our NEOs contain provisions that provide for accelerated vesting upon either a “Change in Control,” or the death or “Disability” of the executive. A “Change in Control” is defined pursuant to the LTIP as the occurrence of one or more of the following events: (1) any person or group becomes the beneficial owner of fifty percent or more of our voting power or voting securities, unless such person or group is Hicks, Muse, Tate & Furst Incorporated or an affiliate of such corporation, (2) the complete liquidation of either the Company, our General Partner, or us; (3) the sale of all or substantially all of the company’s, our General Partner’s, or our assets to anyone other than an entity that is wholly owned by one or more of the company, the General Partner, or us. An executive’s Disability will have occurred at the point that the executive would be entitled to receive benefits under our long-term disability plan.

The following table quantifies the amounts that each NEO would be entitled to receive upon a termination of employment or a change of control, as applicable, assuming that such event occurred on December 31, 2008. The precise amount that any NEO would receive cannot be determined with any certainty until an actual termination or change of control has occurred, but the following are our best estimates as to the amounts that the NEOs are entitled to as of December 31, 2008, and using our closing stock price on that date of $8.05. We have assumed for purposes of this table that all salary and reimbursable expenses were current, and that no vacation had accrued as of December 31, 2008. For the NEOs that resigned or transitioned into a consulting agreement during the 2008 year, we have provided the amount that each NEO actually received pursuant to his termination of employment and transition.

Executive	Death or Disability		Change in Control		Without Cause or for Good Reason		Transition to Consulting Status
Byron R. Kelley								N/A
CEO Severance Payment(1)		N/A		N/A	$	1,900,000
Accelerated Equity(2)	$	855,715	$	855,715		N/A
Continued Medical(3)		N/A		N/A	$	10,524
Supplemental Disability Benefits(4)	$	280,000	$	855,715		N/A
Total	$	1,135,715	$	855,715	$	1,910,524
James W. Hunt(5)		N/A		N/A		N/A	$	301,500
Richard D. Moncrief(6)		N/A		N/A		N/A
Resignation Payment							$	262,500
Continued Medical							$	5,262
Total							$	267,762
Randall H. Dean		N/A		N/A				N/A
Severance Payment(7)					$	633,800
Continued Medical(8)					$	22,824
Total					$	656,624
Dan A. Fleckman								N/A
Severance Payment(9)		N/A		N/A	$	588,563
Continued Medical(10)		N/A		N/A	$	7,812
Accelerated Equity(11)	$	603,750	$	603,750		N/A
Total	$	603,750	$	603,750	$	596,375
Lawrence B. Connors(12)	$	60,375	$	60,375		N/A		N/A

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(1) This amount was calculated by multiplying Mr. Kelley’s base salary by four. We have assumed for purposes of this table that we did not waive the non-compete provisions and will pay the CEO Severance Payment using the maximum multiplier of four, although the amount that he could receive could be reduced by half if we determine to waive such provisions upon his actual termination of employment. This amount also reflects the correct amount that Mr. Kelley would receive if the termination without Cause or for Good Reason occurred in connection with a Change in Control.

(2) This amount was calculated by multiplying the number of restricted units Mr. Kelley held on December 31, 2008 (106,300 units) by our closing stock price of $8.05.

(3) This amount was calculated by multiplying the monthly COBRA premium amount of $877 for twelve months.

(4) As of December 31, 2008, our long-term disability plan would cap monthly benefits at $15,000, leaving a remaining balance of $8,750. Mr. Kelley would receive this supplemental payment until he reaches the age of 65, and so the amount reflected here was calculated my multiplying $8,750 by thirty-two months.

(5) This amount was calculated by multiplying $33,500 by the nine months of consulting services that Mr. Hunt provided to us during the 2008 year.

(6) Mr. Moncrief received the Resignation Payment in consideration for the Resignation and Release Agreement that he entered into with us on December 12, 2008, though the amount was not actually paid to Mr. Moncrief until January of 2009. The amount of Mr. Moncrief’s continued medical expenses were determined by using the monthly COBRA premium amount of $877 for six months.

(7) Mr. Dean’s employment agreement provides for a potential annual bonus of 100 percent of his base salary, and using the assumption that 100 percent of the bonus target was achieved for the 2008 year, this amount is two times his base salary for 2008. This amount also assumes that upon a termination for Good Reason, such Good Reason event was not one of the articulated events in (iii) through (vi) above in Mr. Dean’s Good Reason definition that would prevent him from receiving a portion of this payment, thus the amount Mr. Dean received upon a Good Reason termination could potentially be reduced by half.

(8) This amount was calculated by multiplying the monthly COBRA premium amount of $634 by thirty-six months.

(9) This amount was calculated by subtracting $150,000, the amount of salary we paid to Mr. Fleckman during the 2008 year, from $900,000. We then subtracted the amount of the bonus Mr. Fleckman would have been entitled to receive for the 2008 year assuming 100 percent of targets were achieved, or $161,437.

(10) This amount was calculated by multiplying the monthly COBRA premium amount of $434 by eighteen months.

(11) This amount was calculated by multiplying the number of restricted units Mr. Fleckman held on December 31, 2008 (75,000 units) by our closing stock price of $8.05.

(12) This amount was calculated by multiplying the number of restricted units Mr. Connors held on December 31, 2008 (7,500 units) by our closing stock price of $8.05.

Directors’ Compensation

The directors of the General Partner who are not employees of the General Partner or affiliated with the General Partner’s controlling security holder received in 2008 an annual retainer of $30,000, a flat fee of $1,000 for each meeting of the board and $500 for each committee attended in person, a flat fee of $500 for each such meeting attended by telephone and fees at specified rates for consulting services. These amounts are determined on an annual basis by our board. In addition, those directors are eligible to participate in equity-based compensation plans of the General Partner. Determinations as to any such participation are made by the non-participating directors.

95

Director Compensation for 2008

The following table presents the cash, equity awards and other compensation earned, paid or awarded to each of our directors during the year ended December 31, 2008.

Name	Fees Earned or Paid	Stock Awards(2)	Total ($)
Michael J. Bradley(1)	44,000	38,904	82,904
James F. Burgoyne(4)	39,500	—	39,500
Daniel R. Castagnola(4)	40,000	—	40,000
A. Dean Fuller(3)	32,000	—	32,000
Rodney L. Gray(1)	35,000	29,060	64,060
Paul J. Halas(4)	38,000	—	38,000
Mark T. Mellana(4)	41,000	—	41,000
John T. Mills(1)	52,125	38,904	91,029
Brian P. Ward(4)	36,500	—	36,500
J. Otis Winters(3)	30,375	—	30,375

(1) Messrs. Michael J. Bradley, Rodney L. Gary and John T. Mills were granted 5,000 units. The grant date fair value, are $155,300, $138,750 and $155,300 respectively.

(2) Each amount represents the earned portion of an award of 5,000 units awarded to each of the outside directors. The amounts included in the “Stock Award” column is the dollar amount of compensation expense we recognized for the fiscal year ended December 31, 2008 in accordance with the statement of Financial Accounting Standard No. 123(R).

(3) Messer. A. Dean Fuller and J. Otis Winters resigned from the board of directors on March 12, 2008 and January 24, 2008, respectively.

(4) Messer. Burgoyne, Castagnola, Halas, Mellana and Ward are officers of GE EFS, a related party. All fees paid to these Directors were remitted directly to GE EFS.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth, as of February 18, 2009, the beneficial ownership of our units by:

• each person who then owned beneficially 5 percent or more of our units;

• each member of the Board of Directors of Regency GP LLC;

• each named executive officer of Regency GP LLC; and

• all directors and executive officers of Regency GP LLC, as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

96

Name of Beneficial Owner	Common Units	Percentage of Outstanding Common Units
Aircraft Services Corp(3)	24,679,557	30.4	%
CDMR Holdings LLC(2)	7,276,506	9.0	%
Kayne Anderson Capital Advisors, L.P.	6,601,879	8.1	%
Neuberger Berman LLC	4,938,026	6.1	%
Byron R. Kelley	—	*
James W. Hunt	639,732	0.8	%
Stephen L. Arata(1)	207,973	0.3	%
Dan A. Fleckman	—	*
Randall H. Dean	831,034	1.0	%
Richard D. Moncrief	28,488	*
Lawrence B. Connors(1)	91,313	0.1	%
Michael T. Bradley	1,250	*
James F. Burgoyne	—	*
Daniel R. Castagnola	—	*
Rodney Gray	—	*
Paul J. Halas	—	*
Mark T. Mellana	—	*
John T. Mills	6,250	*
Brian P. Ward	—	*
All directors and executive officers as a group (24 persons)	2,229,533	2.8	%
Total number of units as of February 18, 2009	81,197,103

(1) The common unit amount includes unit options which are currently exercisable in the following amount of common units: Mr. Arata - 35,000 and Mr. Connors - 15,000.

(2) CDMR Holdings, LLC is owned by four entities: two investment limited partnerships affiliated with Carlyle/Riverstone Global Energy and Power Fund II, L.P. (collectively the “Carlyle/Riverstone Entities”), and two entities owned primarily by certain members of management of our contract compression segment (the “Management Entities”). The Carlyle/Riverstone Entities and the Management Entities have a 67 percent and a 33 percent ownership interest in CDMR Holdings, LLC, respectively. The Carlyle/Riverstone Entities are C/R CDM Holdings II, L.P. and C/R CDM Investment Partnership III, L.P. The Carlyle/Riverstone Entities are associated with Riverstone Holdings LLC (“Riverstone”) and The Carlyle Group (“Carlyle”). The address of the Carlyle/Riverstone Entities and Riverstone is 712 Fifth Avenue, 51st Floor, New York, NY 10019. The address of Carlyle is 1001 Pennsylvania Avenue, N.W., Suite 200, Washington, D.C. 20004. The Carlyle/Riverstone Entities are ultimately controlled by a management committee. The Management Entities are CDM Investments, Ltd. and CDM Compression, LLC.

(3) Aircraft Services Corp is an affiliate of GECC.

* Ownership percentages are less than 0.1 percent.

Securities Authorized for Issuance under Equity Compensation Plans. The following table provides information concerning common units that may be issued under the General Partner LTIP. The LTIP consists of restricted units, phantom units and unit options. It currently permits the grant of awards covering an aggregate of 2,865,584 units. The LTIP is administered by the compensation committee of the Board of Directors of our General Partner.

97

Our General Partner’s Board of Directors, or its compensation committee, in its discretion may terminate, suspend or discontinue the LTIP at any time with respect to any award that has not yet been granted. Our General Partner’s Board of Directors, or its compensation committee, also has the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

The following table summarizes the number of securities remaining available for future issuance under the LTIP plan as of February 18, 2009.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders		$	—	—
Equity compensation plans not approved by security holders
Long-Term Incentive Plan holders(1)	381,618		25.94	270,384
Total	381,618	$	25.94	270,384

(1) The long-term incentive plan currently permits the grant of awards covering an aggregate of 2,865,584 units. For more information, which did not require approval by our limited partners, refer to Item  11. “Executive Compensation-Components of Compensation”.

Item 13. Certain Relationships and Related Transactions, and Director Independence

On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC, as administrative agent, the lenders party thereto and the guarantors party thereto. The commitments under the revolving credit facility will terminate automatically on the earlier to occur of the effectiveness of an amendment to the Partnership’s fourth amended and restated credit agreement and April 30, 2009, and the Partnership will be required to prepay all outstanding loans upon the effectiveness of the amendment to the fourth amended and restated credit agreement. The maturity date under the revolving credit facility will be the earlier of the date that is three months after the final maturity date under the fourth amended and restated credit agreement and November 15, 2011.

Upon closing of the joint venture with GECC and the Alinda Investors, the Partnership will enter into an Area of Mutual Interest Agreement pursuant to which it will agree to offer the joint venture the first option to acquire or pursue certain natural gas transportation and storage opportunities identified by the Partnership in a defined area of northern Louisiana prior to the Partnership engaging in such opportunities outside of the joint venture.

Further information required for this item is provided in Item 1—Business—Overview, Item 10—“Directors, Executive Officers and Corporate Governance” and Note 12, Related Party Transactions, include in the notes to the audited consolidated financial statements included in Item 8—“Financial Statements and Supplementary Data.”

98

Item 14. Principal Accounting Fees and Services

Appointment of Independent Registered Public Accountant. The Audit Committee retained KPMG LLP as our principal accountant to conduct the audit of our financial statements for the year ended December 31, 2008 and 2007. Deloitte & Touche LLP served as our independent registered public accountant until June 18, 2007.

Audit Fees. The following table sets forth fees billed by KPMG LLP and Deloitte & Touche LLP for the professional services rendered for the audits of our annual financial statements and other services rendered for the years ended December 31, 2008 and 2007:

	KPMG LLP				Deloitte & Touche LLP
	December 31,				December 31, 2007
	2008		2007
Audit fees(1)		1,732		2,062		335
Audit related fees(2)		31		50		53
Tax fees(3)		10		—		211
All other fees(4)		—		—		—
Total	$	1,773	$	2,112	$	599

(1) Includes fees for audits of annual financial statements, including the audit of internal control over financial reporting, reviews of related quarterly financial statements, and services that are normally provided by independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC.

(2) Includes fees related to consultation concerning financial accounting and reporting standards.

(3) Includes fees related to professional services for tax compliance, tax advice and tax planning.

(4) Consists of fees for services other than services reported above.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountant. Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting, and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and to establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by KPMG LLP or Deloitte & Touche LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

• the auditors’ internal quality-control procedures;

• any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

• the independence of the external auditors;

• the aggregate fees billed by our external auditors for each of the previous two fiscal years; and

• the rotation of the lead partner.

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Part IV

Item 15. Exhibits and Financial Statement Schedules

(a)1. Financial Statements. See “Index to Financial Statements” set forth on page F-1.

(a)2. Financial Statement Schedules. Other schedules are omitted because they are not required or applicable, or the required information is included in the Consolidated Financial Statements or related notes.

(a)3. Exhibits. See “Index to Exhibits.”

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

REGENCY ENERGY PARTNERS LP
By:	REGENCY GP LP, its general partner
By:	REGENCY GP LLC, its general partner
By:	/s/    BYRON R. KELLEY
	Byron R. Kelley
	Chief Executive Officer and officer duly authorized to sign on behalf of the registrant

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date
/s/    BYRON R. KELLEY         Byron R. Kelley	Chairman, President, and Chief Executive Officer (Principal Executive Officer)	March 1, 2009
/s/    STEPHEN L. ARATA         Stephen L. Arata	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 1, 2009
/s/    LAWRENCE B. CONNORS         Lawrence B. Connors	Senior Vice President, Finance and Accounting (Principal Accounting Officer)	March 1, 2009
/s/    JAMES F. BURGOYNE         James F. Burgoyne	Director	March 1, 2009
/s/    DANIEL R. CASTAGNOLA         Daniel R. Castagnola	Director	March 1, 2009
/s/    RODNEY L. GRAY         Rodney L. Gray	Director	March 1, 2009
/s/    MARK T. MELLANA         Mark T. Mellana	Director	March 1, 2009
/s/    JOHN T. MILLS         John T. Mills	Director	March 1, 2009
/s/    BRIAN P. WARD         Brian P. Ward	Director	March 1, 2009
/s/    MICHAEL J. BRADLEY         Michael J. Bradley	Director	March 1, 2009
/s/    PAUL J. HALAS         Paul J. Halas	Director	March 1, 2009

101

Index to Exhibits

Exhibit Number	Description	Incorporated by Reference from Form	Date Filed or File No.
2.1	Contribution Agreement by and among Regency Energy Partners LP, Regency Gas Services LP, as Buyer and HMTF Gas Partners II, L.P., as Seller dated July 12, 2006	8-K	August 14, 2006
2.2	Stock Purchase Agreement by and among Regency Energy Partners LP, Pueblo Holdings, Inc., as Buyer, Bear Cub Investments, LLC, the Members of Bear Cub Investments, LLC identified herein, as Sellers, and Robert J. Clark, as Sellers’ Representative dated April 2, 2007	8-K	April 3, 2007
2.3	Agreement and Plan of Merger among CDM Resource Management, Ltd., the Partners thereof, as listed on the signature pages hereof, Regency Energy Partners LP and ADJHR, LLC dated as of December 11, 2007	8-K	December 11, 2007
2.4	Contribution Agreement by and among Regency Energy Partners LP, Regency Gas Services LP, as Buyer, and ASC Hugoton LLC and FrontStreet EnergyOne LLC as Sellers dated December 10, 2007 and joined in by Aircraft Services Corporation (solely for purposes of Section 2.3(g) hereof)	8-K	December 10, 2007
2.5	Agreement and Plan of Merger among Nexus Gas Partners, LLC, Nexus Gas Holdings, LLC, Regency Energy Partnes LP and Regency NX, LLC	8-K	March 26, 2008
3.1	Certificate of Limited Partnership of Regency Energy Partners LP	S-1	333-128332
3.2	Form of Amended and Restated Limited Partnership Agreement of Regency Energy Partners LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)	S-1	333-128332
3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	August 14, 2006
3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	September 21, 2006
3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	January 8, 2008
3.2.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	January 16, 2008
3.2.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	August 28, 2008
3.2.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP	8-K	February 27, 2009
3.3	Certificate of Formation of Regency GP LLC	S-1	333-128332
3.4	Form of Amended and Restated Limited Liability Company Agreement of Regency GP LLC	S-1	333-128332
3.5	Certificate of Limited Partnership of Regency GP LP	S-1	333-128332
3.6	Form of Amended and Restated Limited Partnership Agreement of Regency GP LP	S-1	333-128332
4.1	Form of Common Unit Certificate	S-1	333-128332

Exhibit Number	Description	Incorporated by Reference from Form	Date Filed or File No.
4.2	Indenture for 8 3/8 percent Senior Notes due 2013, together with the global notes	10-K	March 30, 2007
10.1	Regency GP LLC Long-Term Incentive Plan	S-1	333-128332
10.2	Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan—Unit Option Grant	S-1	333-128332
10.3	Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan—Restricted Unit Grant	S-1	333-128332
10.4	Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan—Phantom Unit Grant (With DERS)	S-1	333-128332
10.5	Form of Grant Agreement for the Regency GP LLC Long-Term Incentive Plan—Phantom Unit Grant (Without DERS)	S-1	333-128332
10.6	Form of Contribution, Conveyance and Assumption Agreement	S-1	333-128332
10.7	Amended Executive Employment Agreement dated March 17, 2008 between the Registrant and Byron R. Kelley
10.8	Severance Agreement with Dan A. Fleckman	10-Q	March 31, 2008
10.9	Amended Executive Employment Agreement dated January 15, 2008 between the Registrant and Randall Dean
10.10	Form of Indemnification Agreement between Regency GP LLC and Indemnities	S-1	333-128332
10.11	Form of Omnibus Agreement	S-1	333-128332
10.12	Amended and Restated Credit Agreement of Regency Gas Services LLC	S-1	333-128332
10.13	Amended and Restated Second Lien Credit Agreement of Regency Gas Services LLC	S-1	333-128332
10.14	Second Amended and Restated Credit Agreement of Regency Gas Services LLC	S-1	333-128332
10.15	Form of Third Amended and Restated Credit Agreement of Regency Gas Services LLC	S-1	333-128332
10.16	Form of Fourth Amended and Restated Credit Agreement of Regency Gas Services LP	8-K	August 14, 2006
10.17	Form of Amendment Agreement No. 3 with respect to the Fourth Amended and Restated Credit Agreement of Regency Gas Services LP dated September 28, 2007	8-K	October 3, 2007
10.18	Form of Amendment Agreement No. 4 with respect to the Fourth Amended and Restated Credit Agreement of Regency Gas Services LP dated January 15, 2008	8-K	February 12, 2008
10.19	Form of Amendment Agreement No. 5 with respect to the Fourth Amended and Restated Credit Agreement of Regency Gas Services LP dated February 14, 2008	8-K	February 19, 2008
10.20	Form of Amendment Agreement No. 6 with respect to the Fourth Amended and Restated Credit Agreement of Regency Gas Services LP dated May 9, 2008	8-K	October 16, 2008

Exhibit Number	Description	Incorporated by Reference from Form	Date Filed or File No.
10.21	Form of Master Lease Agreement of CDM Resource Management LLC
10.22	Form of Revolving Credit Agreement dated as of February 26, 2009 of Regency Energy Partners LP
12.1	Computation of Ratio of Earnings to Fixed Charges
14.1	Code of Business Conduct	10-K	March 30, 2007
16.1	Letter from Deloitte & Touche LLP to the Securities and Exchange Commission dated June 18, 2007	8-K	June 19, 2007
21.1	List of Subsidiaries of Regency Energy Partners LP
23.1	Consent of KPMG LLP
23.2	Consent of Deloitte & Touche LLP
24.1†	Form by Power of Attorney
31.1	Certifications pursuant to Rule 13a-14(a).
31.2	Certifications pursuant to Rule 13a-14(a).
32.1	Certifications pursuant to Section 1350.
32.2	Certifications pursuant to Section 1350.

† Incorporated by reference to the signature page of this filing.

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm as of and for the years ended December  31, 2008 and 2007	F-2
Report of Independent Registered Public Accounting Firm as of and for the year ended December  31, 2008	F-3
Report of Independent Registered Public Accounting Firm for the year ended December 31, 2006	F-4
Consolidated Balance Sheets as of December 31, 2008 and 2007	F-5
Consolidated Statements of Operations for the years ended December 31, 2008, 2007, and 2006	F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December  31, 2008, 2007, and 2006	F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007, and 2006	F-8
Consolidated Statements of Member Interest and Partners’ Capital for the years ended December  31, 2008, 2007, and 2006	F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited the accompanying consolidated balance sheets of Regency Energy Partners LP and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital for the years 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 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. 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 audits provide 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, 2008 and 2007, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2009 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 1, 2009

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Regency Energy Partners LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Regency Energy Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Regency Energy Partners LP acquired CDM Resource Management, Ltd. (CDM) during 2008, and management excluded from its assessment of the effectiveness of Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, CDM’s internal control over financial reporting associated with total assets of $881,552,000 and total revenues of $132,549,000 included in the consolidated financial statements of Regency Energy Partners LP and subsidiaries as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of Regency Energy Partners LP also excluded an evaluation of the internal control over financial reporting of CDM.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Regency Energy Partners LP as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital for the years then ended, and our report dated March 1, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

March 1, 2009

F-3

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 statements of operations, member interest and partners’ capital, comprehensive income (loss) and cash flows of Regency Energy Partners LP and subsidiaries (the “Partnership”) for the year ended December 31, 2006. 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 audit.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of the Partnership’s operations and cash flows for the year ended December 31, 2006, 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)

F-4

Regency Energy Partners LP

Consolidated Balance Sheets

(in thousands except unit data)

	December 31, 2008			December 31, 2007
ASSETS
Current Assets:
Cash and cash equivalents	$	599		$	32,971
Restricted cash		10,031			6,029
Trade accounts receivable, net of allowance of $941 in 2008 and $61 in 2007		40,875			16,487
Accrued revenues		96,712			117,622
Related party receivables		855			61
Assets from risk management activities		73,993			—
Other current assets		13,338			6,723
Total current assets		236,403			179,893
Property, plant and equipment
Gathering and transmission systems		652,267			635,206
Compression equipment		799,527			145,555
Gas plants and buildings		156,246			134,300
Other property, plant and equipment		167,256			105,399
Construction-in-progress		154,852			33,552
Total property, plant and equipment		1,930,148			1,054,012
Less accumulated depreciation		(226,594	)		(140,903	)
Property, plant and equipment, net		1,703,554			913,109
Other Assets:
Intangible assets, net of accumulated amortization of $22,517 in 2008 and $8,929 in 2007		205,646			77,804
Long-term assets from risk management activities		36,798			—
Goodwill		262,358			94,075
Other, net of accumulated amortization of debt issuance costs of $5,246 in 2008 and $2,488 in 2007		13,880			13,529
Total other assets		518,682			185,408
TOTAL ASSETS	$	2,458,639		$	1,278,410
LIABILITIES & PARTNERS’ CAPITAL
Current Liabilities:
Trade accounts payable	$	65,483		$	48,904
Accrued cost of gas and liquids		76,599			96,026
Related party payables		—			50
Escrow payable		10,031			6,029
Liabilities from risk management activities		42,691			37,852
Other current liabilities		22,146			9,397
Total current liabilities		216,950			198,258
Long-term liabilities from risk management activities		560			15,073
Other long-term liabilities		15,487			15,393
Long-term debt		1,126,229			481,500
Minority interest in consolidated subsidiary		13,161			4,893
Commitments and contingencies
Partners’ Capital:
Common units (55,519,903 and 41,283,079 units authorized; 54,796,701 and 40,514,895 units issued and outstanding at December 31, 2008 and 2007)		764,161			490,351
Class D common units (7,276,506 units authorized, issued and outstanding at December 31, 2008)		226,759			—
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, 2008 and 2007)		(1,391	)		7,019
General partner interest		29,283			11,286
Accumulated other comprehensive income (loss)		67,440			(38,325	)
Total partners’ capital		1,086,252			563,293
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,458,639		$	1,278,410

See accompanying notes to consolidated financial statements

F-5

Regency Energy Partners LP

Consolidated Statements of Operations

(in thousands except unit data and per unit data)

	Year Ended December 31,
	2008			2007			2006
REVENUES
Gas sales	$	1,126,760		$	744,681		$	560,620
NGL sales		409,476			347,737			256,672
Gathering, transportation and other fees, including related party amounts of $3,763, $1,350 and $2,160		286,507			100,644			63,071
Net realized and unrealized loss from risk management activities		(21,233	)		(34,266	)		(7,709	)
Other		62,294			31,442			24,211
Total revenues		1,863,804			1,190,238			896,865
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $1,878, $14,165 and $1,630		1,408,333			976,145			740,446
Operation and maintenance		131,629			58,000			39,496
General and administrative		51,323			39,713			22,826
Loss on asset sales, net		472			1,522			—
Management services termination fee		3,888			—			12,542
Transaction expenses		1,620			420			2,041
Depreciation and amortization		102,566			55,074			39,654
Total operating costs and expenses		1,699,831			1,130,874			857,005
OPERATING INCOME		163,973			59,364			39,860
Interest expense, net		(63,243	)		(52,016	)		(37,182	)
Loss on debt refinancing		—			(21,200	)		(10,761	)
Other income and deductions, net		332			1,252			839
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST		101,062			(12,600	)		(7,244	)
Income tax expense (benefit)		(266	)		931			—
Minority interest		312			305			—
NET INCOME (LOSS)	$	101,016		$	(13,836	)	$	(7,244	)
Less: Net income from January 1-31, 2006		—			—			1,564
Net income (loss) for partners	$	101,016		$	(13,836	)	$	(8,808	)
General partner’s interest in current period net income (loss), including IDR		9,967			(393	)		(176	)
Beneficial conversion feature for Class C common units		—			1,385			3,587
Beneficial conversion feature for Class D common units		7,199			—
Limited partners’ interest in net income (loss)	$	83,850		$	(14,828	)	$	(12,219	)
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	83,850		$	(20,620	)	$	(11,333	)
Weighted average number of common and subordinated units outstanding		66,042,830			51,056,769			38,207,792
Basic income (loss) per common and subordinated unit	$	1.27		$	(0.40	)	$	(0.30	)
Diluted income (loss) per common and subordinated unit	$	1.24		$	(0.40	)	$	(0.30	)
Distributions per unit	$	1.71		$	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
Income per Class B common unit	$	—		$	—		$	(0.17	)
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class C common units	$	—		$	1,385		$	3,587
Total number of 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 D common units	$	7,199		$	—		$	—
Total number of Class D common units outstanding		7,276,506			—			—
Income per Class D common unit due to beneficial conversion feature	$	0.99		$	—		$	—
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class E common units	$	—		$	5,792		$	—
Total number of 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

F-6

Regency Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Year Ended December 31,
	2008		2007			2006
Net income (loss)	$	101,016	$	(13,836	)	$	(7,244	)
Net hedging amounts reclassified to earnings		35,512		19,362			1,815
Net change in fair value of cash flow hedges		70,253		(58,706	)		10,166
Comprehensive income (loss)	$	206,781	$	(53,180	)	$	4,737

See accompanying notes to consolidated financial statements

F-7

Regency Energy Partners LP

Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2008			2007			2006
OPERATING ACTIVITIES
Net income (loss)	$	101,016		$	(13,836	)	$	(7,244	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		105,324			57,069			39,287
Write-off of debt issuance costs		—			5,078			10,761
Equity income and minority interest in earnings		312			262			(532	)
Risk management portfolio valuation changes		(14,700	)		14,667			(2,262	)
Loss on asset sales		472			1,522			—
Unit based compensation expenses		4,306			15,534			2,906
Gain on insurance settlements		(3,282	)		—			—
Cash flow changes in current assets and liabilities:
Trade accounts receivable and accrued revenues, and related party receivables		18,648			(28,789	)		(5,506	)
Other current assets		(6,615	)		(1,394	)		104
Trade accounts payable, accrued cost of gas and liquids, and related party payables		(40,772	)		30,089			(1,359	)
Other current liabilities		12,749			(149	)		3,640
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		3,840			554			3,283
Net cash flows provided by operating activities		181,298			79,529			44,156
INVESTING ACTIVITIES
Capital expenditures		(375,083	)		(129,784	)		(142,423	)
Acquisitions		(577,668	)		(34,855	)		(81,695	)
Acquisition of investment in unconsolidated subsidiary, net of $100 cash		—			(5,000	)		—
Proceeds from asset sales		840			11,706			—
Proceeds from insurance settlements		3,282			—			—
Other		—			—			468
Net cash flows used in investing activities		(948,629	)		(157,933	)		(223,650	)
FINANCING ACTIVITIES
Net borrowings under revolving credit facilities		644,729			59,300			14,700
Borrowings under credit facilities		—			—			599,650
Repayments under credit facilities		—			(50,000	)		(858,600	)
Proceeds (repayments) of senior notes, net of debt issuance costs		—			(192,500	)		536,175
Partner contributions		11,746			7,735			3,786
Partner distributions		(120,591	)		(79,933	)		(37,144	)
Proceeds from option exercises		2,700			—			—
Debt issuance costs		(2,940	)		(2,427	)		(10,488	)
Proceeds from equity issuances, net of issuance costs		199,315			353,546			312,700
FrontStreet distributions		—			(9,695	)		—
FrontStreet contributions		—			13,417			—
Acquisition of assets between entities under common control		—			—			(62,074	)
Borrowings under TexStar loan agreement		—			—			85,000
Repayments under TexStar loan agreement		—			—			(155,000	)
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	)
Net cash flows provided by financing activities		734,959			99,443			184,947
Net increase (decrease) in cash and cash equivalents		(32,372	)		21,039			5,453
Cash and cash equivalents at beginning of period		32,971			9,139			3,686
Cash acquired from FrontStreet		—			2,793			—
Cash and cash equivalents at end of period	$	599		$	32,971		$	9,139
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	59,969		$	67,844		$	33,347
Income taxes paid		605			—			—
Non-cash capital expenditures in accounts payable		25,845			7,761			23,822
Non-cash capital expenditure 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 an acquisition		219,560			19,724			—

See accompanying notes to consolidated financial statements

F-8

Regency Energy Partners LP

Consolidated Statements of Member Interest and Partners’ Capital

(in thousands except unit data)

	Units										Member Interest			Common Unitholders
	Common		Class B		Class C		Class D	Class E		Subordinated
Balance—December 31, 2005	—		—		—		—	—		—	$	241,924		$	—
Net income through January 31, 2006	—		—		—		—	—		—		1,564			—
Net hedging loss reclassified to earnings	—		—		—		—	—		—		—			—
Net change in fair value of cash flow hedges	—		—		—		—	—		—		—			—
Balance—January 31, 2006	—		—		—		—	—		—		243,488			—
Contribution of net investment to unitholders	5,353,896		—		—		—	—		19,103,896		(182,320	)		89,337
Proceeds from IPO, net of issuance costs	13,750,000		—		—		—	—		—		—			125,907
Net proceeds from exercise of over allotment option	1,400,000		—		—		—	—		—		—			26,163
Over allotment option net proceeds to HM Capital Investors	(1,400,000	)	—		—		—	—		—		—			(26,163	)
Capital reimbursement to HM Capital Partners	—		—		—		—	—		—		—			(119,441	)
Offering costs	—		—		—		—	—		—		—			(2,056	)
Issuance of Class B Common Units for TexStar member interest	—		5,173,189		—		—	—		—		(61,168	)		—
Payment to HM Capital for TexStar net of repayment of promissory note	—		—		—		—	—		—		—			(30,418	)
Other	—		—		—		—	—		—		—			(64	)
Issuance of Class C Common Units net of costs	—		—		2,857,143		—	—		—		—			—
Issuance of restricted common units	516,500		—		—		—	—		—		—			—
Unit based compensation expenses	—		—		—		—	—		—		—			1,339
General partner contributions					—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(18,409	)
Net loss from February 1 through December 31, 2006	—		—		—		—	—		—		—			(4,003	)
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		—			42,192
Conversion of Class B and C to common units	8,030,332		(5,173,189	)	(2,857,143	)	—	—		—		—			120,663
Issuance of common units for acquisition	751,597		—		—		—	—		—		—			19,724
Issuance of common units	11,500,000		—		—		—	—		—		—			353,446
Issuance of restricted common units, net of forfeitures	565,167		—		—		—	—		—		—			—
Exercise of common unit options	47,403		—		—		—	—		—		—			100
Unit based compensation expenses	—		—		—		—	—		—		—			15,534
General partner contributions	—		—		—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(49,296	)
Acquisition of FrontStreet	—		—		—		—	4,701,034		—		—			—
FrontStreet contributions	—		—		—		—	—		—		—			—
FrontStreet distributions	—		—		—		—	—		—		—			—
Net (loss) income	—		—		—		—	—		—		—			(12,037	)
Other	—		—		—		—	—		—		—			25
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		—			490,351
Issuance of Class D common units	—		—		—		7,276,506	—		—		—			—
Issuance of restricted common units and option exercises, net of forfeitures	559,863		—		—		—	—		—		—			2,700
Issuance of common units	9,020,909		—		—		—	—		—		—			199,315
Working capital adjustment on FrontStreet	—		—		—		—	—		—		—			—
Conversion of Class E common units	4,701,034		—		—		—	(4,701,034	)	—		—			92,104
Unit based compensation expenses	—		—		—		—	—		—		—			4,306
General partner contributions	—		—		—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(84,207	)
Net income	—		—		—		—	—		—		—			59,592
Net hedging amounts reclassified to earnings	—		—		—		—	—		—		—			—
Net change in fair value of cash flow hedges	—		—		—		—	—		—		—			—
Balance—December 31, 2008	54,796,701		—		—		7,276,506	—		19,103,896	$	—		$	764,161

See accompanying notes to the consolidated financial statements

F-9

Regency Energy Partners LP

Consolidated Statements of Member Interest and Partners’ Capital—(Continued)

(in thousands except unit data)

	Class B Unitholders			Class C Unitholders			Class D Unitholders		Class E Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Total
Balance—December 31, 2005	$	—		$	—		$	—	$	—		$	—		$	—		$	(10,962	)	$	230,962
Net income through January 31, 2006		—			—			—		—			—			—			—			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		—			—			—		—			—			—			(7,765	)		235,723
Contribution of net investment to unitholders		—			—			—		—			89,337			3,646			—			—
Proceeds from IPO, net of issuance costs		—			—			—		—			125,907			5,139			—			256,953
Net proceeds from exercise of over allotment option		—			—			—		—			—			—			—			26,163
Over allotment option net proceeds to HM Capital Investors		—			—			—		—			—			—			—			(26,163	)
Capital reimbursement to HM Capital Partners		—			—			—		—			(119,441	)		(4,876	)		—			(243,758	)
Offering costs		—			—			—		—			(2,056	)		(83	)		—			(4,195	)
Issuance of Class B Common Units for TexStar member interest		61,168			—			—		—			—			—			—			—
Payment to HM Capital for TexStar net of repayment of promissory note		—			—			—		—			(29,744	)		(1,214	)		—			(61,376	)
Other		(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		146			59			—		—			1,304			58			—			2,906
General partner contributions		—			—			—		—			—			3,786			—			3,786
Partner distributions		—			—			—		—			(18,001	)		(735	)		—			(37,145	)
Net loss from February 1 through December 31, 2006		(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		60,671			59,992			—		—			43,240			5,543			1,019			212,657
Conversion of Class B and C to common units		(60,671	)		(59,992	)		—		—			—			—			—			—
Issuance of common units for acquisition		—			—			—		—			—			—			—			19,724
Issuance of common units		—			—			—		—			—			—			—			353,446
Issuance of restricted common units		—			—			—		—			—			—			—			—
Exercise of common unit options		—			—			—		—			—			—			—			100
Unit based compensation expenses		—			—			—		—			—			—			—			15,534
General partner contributions		—			—			—		—			—			7,735			—			7,735
Partner distributions		—			—			—		—			(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 income (loss)		—			—			—		5,792			(7,198	)		(393	)		—			(13,836	)
Other		—			—			—		—			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		—			—			—		92,962			7,019			11,286			(38,325	)		563,293
Issuance of Class D common units		—			—			219,560		—			—			—			—			219,560
Issuance of restricted common units and option exercises, net of forfeitures		—			—			—		—			—			—			—			2,700
Issuance of common units		—			—			—		—			—			—			—			199,315
Working capital adjustment on FrontStreet		—			—			—		(858	)		—			—			—			(858	)
Conversion of Class E common units		—			—			—		(92,104	)		—			—			—			—
Unit based compensation expenses		—			—			—		—			—			—			—			4,306
General partner contributions		—			—			—		—			—			11,746			—			11,746
Partner distributions		—			—			—		—			(32,668	)		(3,716	)		—			(120,591	)
Net income		—			—			7,199		—			24,258			9,967			—			101,016
Net hedging amounts reclassified to earnings		—			—			—		—			—			—			35,512			35,512
Net change in fair value of cash flow hedges		—			—			—		—			—			—			70,253			70,253
Balance—December 31, 2008	$	—		$	—		$	226,759	$	—		$	(1,391	)	$	29,283		$	67,440		$	1,086,252

See accompanying notes to consolidated financial statements

F-10

Regency Energy Partners LP

Notes to Consolidated Financial Statements

For the Year Ended December 31, 2008

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 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 NGLs as well as providing contract compression services. 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. See Note 5.

On June 18, 2007, indirect subsidiaries 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 and 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. The Partnership was not required to record any adjustments to reflect the acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).

On January 7, 2008, the Partnership acquired all of the outstanding equity and minority interest (the “FrontStreet Acquisition”) of FrontStreet from ASC and EnergyOne. FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party. 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) $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract valued at $3,888,000. The Partnership financed the cash portion of the purchase price with borrowings under its revolving credit facility.

In connection with the FrontStreet Acquisition, the Partnership amended the Partnership Agreement to create the Class E common units. The Class E common units had 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 were issued in a private placement 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 was a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which the Partnership applied the purchase method of accounting.

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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

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.

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 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 $10,031,000 is held in escrow for purchase indemnifications related to the Nexus acquisition and for environmental remediation projects. 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 years ended December 31, 2008, 2007, and 2006, the Partnership capitalized interest of $2,409,000, $1,754,000, and $511,000, 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 did not record any impairment in 2008, 2007 or 2006.

The Partnership accounts for its asset retirement obligations in accordance with 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

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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 $88,828,000, $50,719,000, and $36,880,000 for the years ended December 31, 2008, 2007, and 2006, 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
Compression Equipment	10 - 30
Gas Plants and Buildings	15 - 35
Other property, plant and equipment	3 - 10

Intangible Assets. Intangible assets consisting of (i) permits and licenses, (ii) customer contracts, (iii) trade name, and (iv) customer relations 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 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 2008, 2007, or 2006.

Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination. 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 its 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 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, 2008, 2007, or 2006.

Other Assets, net. Other assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt. Taxes incurred on behalf of, and passed through to, the Partnership’s compression customers are accounted for on a net basis as allowed under EITF 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.”

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, 2008 and 2007 were immaterial.

Revenue Recognition. The Partnership earns revenues from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, and (iii) contract compression services. 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

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associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. 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. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.

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, NGLs prices, processing margins and interest rates. The Partnership uses ethane, propane, butane, natural gasoline, and condensate swaps to create offsetting positions to specific commodity price exposures. The Partnership accounts for derivative financial instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), whereby all derivative financial instruments are 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 medical, dental, and other healthcare benefits to employees. The Partnership provides a matching contribution for employee contributions to their 401(k) accounts, which vests ratably over 3 or 5 years. The amount of matching contributions for the years ended December 31, 2008, 2007, and 2006 was $395,000, $469,000 and $201,000, respectively, and is recorded in general and administrative expenses. The Partnership has no pension obligations or other post employment benefits.

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. 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 $8,156,000 and $8,642,000 as of December 31, 2008

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and 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 of $ 62,000 and deferred income tax benefit of $486,000 using a 35 percent effective rate.

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

Earnings per unit. Basic net income per limited partner unit is computed in accordance with SFAS No. 128, “Earnings Per Share,” as interpreted by EITF Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class method under FASB Statement No. 128.” The general partners’ interest in net income or loss consists of its two percent interest, make-whole allocations for any losses allocated in a prior tax year and incentive distribution rights. After deducting the general partner’s interest, the limited partners’ interest in the remaining net income or loss is allocated to each class of equity units based on distributions and beneficial conversion feature amounts, if applicable, then divided by the weighted average number of common and subordinated 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 units outstanding and the effect of non-vested restricted units and unit options computed using the treasury stock method. Common and subordinated units are considered to be a single class. For special classes of common units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.

Recently Issued Accounting Standards. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. Generally, the effects of SFAS No. 141(R) will depend on future acquisitions.

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

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about derivative and hedging activities. These enhanced disclosures will address (a) how and why a company uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations and (c) how derivative instruments and related hedged items affect a company’s financial position, results of operations and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning on or after November 15, 2008, with earlier adoption allowed. 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 March 2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 defines how to allocate net income among the

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various classes of equity, including incentive distribution rights, narrowing the number of currently acceptable methods. The standard becomes effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted, and EITF No. 07-4 must be applied retrospectively for all financial statements presented. This new standard is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

In April 2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of intangible assets. The objective of FSP 142-3 is to better match the useful life of intangible assets to the cash flow generated. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. Early adoption of this statement is not permitted. The Partnership is currently evaluating the potential impact of this standard on its financial position, results of operations and cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity of GAAP. SFAS 162’s effective date is November 15, 2008. The adoption of SFAS 162 is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). Based on this guidance, the Partnership will include non-vested units granted under its LTIP in the basic earnings per unit calculation. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period earnings per unit data will be adjusted. Early application is not permitted. This new standard is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

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, 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 4,701,034 of Class E common units to ASC as consideration for the FrontStreet Acquisition. The Class E common units had the same terms and conditions

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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. The Class E common units were converted into common units on a one-for-one basis on May 5, 2008.

Class D Common Units. On January 15, 2008, the Partnership issued 7,276,506 of Class D common units to CDM Resource Management Ltd. as partial consideration for the CDM Acquisition. The Class D common units had the same terms and conditions as the Partnership’s common units, except that the Class D common units were not entitled to participate in earnings or distributions by the Partnership. The Class D common units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 under Section 4(2) thereof. The Class D common units were converted into common units without the payment of further consideration on a one-for-one basis on February 9, 2009.

Common Unit Offerings. On July 26, 2007, the Partnership sold 10,000,000 common units for and received $307,680,000 in proceeds, 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 and 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. On August 1, 2008, the Partnership sold 9,020,909 common units and received $204,133,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution.

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.

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 1,656,676 equivalent units as of December 31, 2008. 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

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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 the first day of any quarter beginning after 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. The subordinated units converted into common units on a one-for-one basis on February 17, 2009.

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.

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.

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Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2008 and 2007:

Distribution Date	Cash Distribution
	(per Unit)
November 14, 2008	$	0.4450
August 14, 2008		0.4450
May 14, 2008		0.4200
February 14, 2008		0.4000
November 14, 2007		0.3900
August 14, 2007		0.3800
May 15, 2007		0.3800
February 14, 2007		0.3700
November 14, 2006		0.3700
August 14, 2006		0.3500
May 15, 2006		0.2217

4. Income (Loss) per Limited Partner Unit

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the year ended December 31, 2008.

	For the Year Ended December 31, 2008
	Income (Numerator)		Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)
Basic Earnings per Unit
Limited partner’s interest in net income	$	83,850	66,042,830	$	1.27
Effect of Dilutive Securities
Common unit options		—	30,580
Restricted common units		—	5,468
Class D common units		7,199	7,276,506
Diluted Earnings per Unit	$	91,049	73,355,384	$	1.24

Diluted earnings per unit equals basic because all instruments were antidilutive for the years ended December 31, 2007 and 2006.

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. 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 128.

In connection with the TexStar acquisition, the Partnership issued 5,173,189 of Class B common units to HMTF Gas Partners, an affiliate of HM Capital, which at the time owned a controlling interest in the Partnership. Because this transaction represented the acquisition of an entity under common control, the Partnership applied a method of accounting similar to a pooling of interests. The amount of net income allocated to the Class B common units represents amounts earned by TexStar between the date of common control and the transaction date.

On September 21, 2006, the Partnership issued 2,857,143 Class C common units. The beneficial conversion feature is reflected in income 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.”

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In connection with the CDM acquisition discussed below, the Partnership issued 7,276,506 Class D common units. At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units. This discount represented a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class D common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common units.”

In connection with the FrontStreet acquisition, the Partnership issued 4,701,034 Class E common units to ASC, an affiliate of GECC. Because this transaction represented the acquisition of an entity under common control, the Partnership applied a method of accounting similar to a pooling of interests. The amount of net income allocated to the Class E common units represents amounts earned by FrontStreet between the date of common control and the transaction date. The amount of distributions per unit reflects amounts paid out to the owners of FrontStreet prior to the acquisition.

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented.

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

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.

As previously disclosed in the December 31, 2007 Form 10-K, the Partnership identified and corrected 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”. The error is immaterial and had no impact on the Partnership’s net loss or partners’ capital.

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

	As Previously Reported in the December 31, 2006 Form 10-K			As Restated in the December 31, 2007 Form 10-K*
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 declared per unit	$	—		$	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 declared 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 declared per unit	$	—		$	—

* Amounts included in the consolidated statement of operations for the year ended December 31, 2007 have been recast for as-if pooling accounting treatment for the FrontStreet Acquisition.

5. Acquisitions and Dispositions

2008

FrontStreet. On January 7, 2008, the Partnership acquired all of the outstanding equity and minority interest of FrontStreet from ASC and EnergyOne, which is further described in Note 1, Organization and Basis of Presentation.

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 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.

The total purchase price paid by the Partnership for the partnership interests of CDM consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire 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 with respect to any obligations under the Merger Agreement, including obligations for breaches of representation, warranties and covenants.

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The total purchase price of $699,841,000, including direct transaction costs, was allocated as follows.

	At January 15, 2008
	(in thousands)
Current assets	$	19,463
Other assets		4,658
Gas plants and buildings		1,528
Gathering and transmission systems		420,974
Other property, plant and equipment		2,728
Construction-in-progress		36,239
Identifiable intangible assets		80,480
Goodwill		164,882
Assets acquired		730,952
Current liabilities		(31,054	)
Other liabilities		(57	)
Net assets acquired	$	699,841

Nexus Gas Holdings, LLC. On March 25, 2008, the Partnership acquired Nexus (“Nexus Acquisition”) by merger for $88,486,000 in cash, including customary closing adjustments and direct transaction costs. 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 its existing revolving credit facility.

The total purchase price of $88,640,000 was allocated as follows.

	At March 25, 2008
	(in thousands)
Current assets	$	3,457
Buildings		13
Gathering and transmission systems		16,960
Other property, plant and equipment		4,440
Identifiable intangible assets		61,100
Goodwill		3,341
Assets acquired		89,311
Current liabilities		(671	)
Net assets acquired	$	88,640

Upon consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Sonat. Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat Asset Acquisition”) that could facilitate the Nexus gathering system’s integration 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.

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

F-22

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.

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, acquired all the outstanding equity of Pueblo. 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 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 acquired	$	65,313
Current liabilities		(1,187	)
Long-term liabilities		(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

F-23

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.

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
	(in thousands)
Revenue
Regency Energy Partners	$	812,564
TexStar Field Services		84,301
Combined	$	896,865
Net Loss
Regency Energy Partners	$	(1,639	)
TexStar Field Services		(5,605	)
Combined	$	(7,244	)

Como. On July 25, 2006, TexStar acquired certain natural gas gathering, treating and processing assets from the other parties 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.

F-24

The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM, Nexus, Pueblo and Como had occurred as of the beginning of the periods presented. Such unaudited pro forma financial 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.

	Pro Forma Results for the Year Ended December 31,
	2008		2007			2006
	(in thousands except unit and per unit data)
Revenue	$	1,871,011	$	1,317,365		$	952,229
Net income (loss)		102,830		(6,913	)		(6,876	)
Less net income from January 1 – 31, 2006		—		—			1,564
Net income (loss) for partners		102,830		(6,913	)		(8,440	)
Less:
General partner’s interest in current period net income (loss), including IDR		9,833		(255	)		(169	)
Beneficial conversion feature for Class C common units		—		1,385			3,587
Beneficial conversion feature for Class D common units		7,199		—
Limited partners’ interest in net income (loss)	$	85,798	$	(8,043	)	$	(11,858	)
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	85,798	$	(13,835	)	$	(10,999	)
Weighted average number of common and subordinated units outstanding		66,042,830		51,056,769			38,207,792
Basic income (loss) per common and subordinated unit	$	1.30	$	(0.27	)	$	(0.29	)
Diluted income (loss) per common and subordinated unit	$	1.27	$	(0.27	)	$	(0.29	)
Distributions per unit	$	1.71	$	1.52		$	0.9417
Amount allocated to Class B common units	$	—	$	—		$	(859	)
Weighted average number of Class B common units outstanding		—		651,964			5,173,189
Income per Class B common unit	$	—	$	—		$	(0.17	)
Distributions per unit	$	—	$	—		$	—
Amount allocated to Class C common units	$	—	$	1,385		$	3,587
Total number of 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 D common units	$	7,199	$	—		$	—
Total number of Class D common units outstanding		7,276,506		—			—
Income per Class D common unit due to beneficial conversion feature	$	0.99	$	—		$	—
Distributions per unit	$	—	$	—		$	—
Amount allocated to Class E common units	$	—	$	5,792		$	—
Total number of 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

The net fair value of the Partnership’s risk management activities constituted a net asset of $67,540,000 at December 31, 2008 and a net liability of $52,925,000 at December 31, 2007. The Partnership expects to

F-25

reclassify $53,047,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income (loss) in the next twelve months. The Partnership recorded $15,655,000 of net mark-to-market gains for the year ended December 31, 2008 and $14,559,000 of mark-to-market losses for the year ended December 31, 2007 for certain hedges that, did not initially, or do not qualify for hedge accounting. The Partnership also recognized $545,000 of ineffectiveness gain for the year ended December 31, 2008 and $486,000 of ineffectiveness loss for the year ended December 31, 2007.

In the year ended December 31, 2008, the Partnership recorded in net realized and unrealized loss from risk management activities $1,500,000 of losses associated with its credit risk assessment in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).

The Partnership’s hedging positions help reduce exposure to variability of future commodity prices through 2010 and future interest rates on $300,000,000 of long-term debt under its revolving credit facility through March 5, 2010, the date the interest rate swaps expire.

Effective June 19, 2007, the Partnership elected to account for all outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective. At December 31, 2008, the Partnership has the following commodity hedging programs that qualify for hedge accounting: the 2009 NGL, natural gas and West Texas Intermediate crude oil hedging programs and the 2010 West Texas Intermediate crude oil hedging program.

In March 2008, the Partnership entered offsetting trades against its existing 2009 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2009 NGL hedges. This group of trades, along with the pre-existing 2009 NGL 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 133 as cash flow hedges. In May 2008, the Partnership entered into commodity swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane, which are accounted for using mark-to-market accounting.

The Partnership accounts for a portion of its 2008 and, prior to August 2008, accounted for all of its 2009 West Texas Intermediate crude oil swaps using mark-to-market accounting. In August 2008, the Partnership entered into an offsetting trade against its existing 2009 West Texas Intermediate crude oil swap to minimize the volatility of the original 2009 swap. Simultaneously, the Partnership executed an additional 2009 West Texas Intermediate crude oil swap, which was designated under SFAS No. 133 as a cash flow hedge. In May 2008, the Partnership entered into a West Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which was designated as a cash flow hedge in June 2008.

On December 2, 2008, the Partnership entered into two natural gas swaps to hedge its equity exposure to natural gas for calendar year 2009. These natural gas swaps were designated as cash flow hedges under SFAS 133 on December 2, 2008.

On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (1.5 percent as of December 31, 2008) through March 5, 2010. These interest rate swaps were designated as cash flow hedges in March 2008.

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 year ended December 31, 2007 and 2006, respectively, because the hedged forecasted transaction will not occur.

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7. Long-term Debt

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

	December 31, 2008			December 31, 2007
	(in thousands)
Senior notes	$	357,500		$	357,500
Revolving loans		768,729			124,000
Total		1,126,229			481,500
Less: current portion		—			—
Long-term debt	$	1,126,229		$	481,500
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	500,000
Unfunded Lehman commitments		(8,646	)		—
Revolving loans		(768,729	)		(124,000	)
Letters of credit		(16,257	)		(27,263	)
Total available	$	106,368		$	348,737

Long-term debt maturities as of December 31, 2008 for each of the next five years are as follows.

Year Ending December 31,	Amount
	(in thousands)
2009	$	—
2010		—
2011		768,729
2012		—
2013		357,500
Thereafer		—
Total	$	1,126,229

In the year ending December 31, 2008, the Partnership borrowed $844,729,000 under its revolving credit facility; these borrowings were made primarily to fund capital expenditures. During the same period, the Partnership repaid $200,000,000 with proceeds from an equity offering. In the years ending December 31, 2007 and 2006, the Partnership borrowed $283,230,000 and $195,300,000 respectively; these funds were used primarily to finance capital expenditure projects and to temporary finance the TexStar acquisition. During the same period, the Partnership repaid $421,430,000 and $180,600,000 of these borrowings with proceeds from private equity offering and term loans.

Senior Notes. In 2006, the Partnership and Finance Corp. 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 8.375 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,

F-27

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, 2008, with the exception of WGP-KHC, LLC, the entity that owns the FrontStreet assets, and Finance Corp. These note guarantees are the joint and several obligations of the Guarantors. Guarantors 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 not guarantee the senior notes, the condensed consolidating financial statements of the guarantors and non-guarantors as of and for the years end December 31, 2008 and 2007 are disclosed below in accordance with Rule 3-10 of Regulation S-X.

Condensed Consolidating Balance Sheets

December 31, 2008

	Guarantors		Non Guarantors		Elimination		Consolidated
	(in thousands)
ASSETS
Total current assets	$	212,712	$	23,691	$	—	$	236,403
Property, plant and equipment, net		1,612,387		91,167		—		1,703,554
Total other assets		518,682		—		—		518,682
TOTAL ASSETS	$	2,343,781	$	114,858	$	—	$	2,458,639
LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	210,241	$	6,709	$	—	$	216,950
Long-term liabilities from risk management activities		560		—		—		560
Other long-term liabilities		15,487		—		—		15,487
Long-term debt		1,126,229		—		—		1,126,229
Minority interest		13,161		—		—		13,161
Partners’ capital		978,103		108,149		—		1,086,252
TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	2,343,781	$	114,858	$	—	$	2,458,639

December 31, 2007

	Guarantors		Non Guarantors		Elimination			Consolidated
	(in thousands)
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

F-28

Condensed Consolidating Statements of Operations

For the Year Ended December 31, 2008

	Guarantors			Non Guarantors			Elimination		Consolidated
	(in thousands)
Total revenues	$	1,816,346		$	47,458		$	—	$	1,863,804
Total operating costs and expenses		1,659,810			40,021			—		1,699,831
OPERATING INCOME		156,536			7,437			—		163,973
Interest expense, net		(63,243	)		—			—		(63,243	)
Other income and deductions, net		446			(114	)		—		332
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		93,739			7,323			—		101,062
Income tax benefit		(266	)		—			—		(266	)
Minority interest		312			—			—		312
NET INCOME	$	93,693		$	7,323		$	—	$	101,016

For the Year Ended December 31, 2007

	Guarantors			Non Guarantors			Elimination		Consolidated
	(in thousands)
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 BEFORE INCOME TAXES AND MINORITY INTEREST		(18,697	)		6,097			—		(12,600	)
Income tax expense		931			—			—		931
Minority interest		—			305			—		305
NET INCOME (LOSS)	$	(19,628	)	$	5,792		$	—	$	(13,836	)

Condensed Consolidating Statements of Cash Flow

For the Year Ended December 31, 2008

	Guarantors			Non Guarantors			Elimination		Consolidated
	(in thousands)
Net cash flows provided by (used in) operating activities	$	181,530		$	(232	)	$	—	$	181,298
Net cash flows used in investing activities		(935,848	)		(12,781	)		—		(948,629	)
Net cash flows provided by financing activities		727,095			7,864			—		734,959

For the Year Ended December 31, 2007

	Guarantors			Non Guarantors			Elimination		Consolidated
	(in thousands)
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 financing activities		95,721			3,722			—		99,443

F-29

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 of its subsidiaries, except certain wholly owned subsidiaries. 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, 2007, RGS’ Fourth Amended and Restated Credit Agreement (“Credit Facility”) allowed for borrowings of $600,000,000 in term loans and $500,000,000 in a revolving credit facility. The availability for letters of credit was increased to $100,000,000. RGS has the option to increase the commitments under the revolving credit facility or the term loan facility, or both, by an amount up to $250,000,000 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 January 15, 2008, the revolving credit facility under the Credit Facility was expanded to $750,000,000 and on February 13, 2008, the revolving credit facility under the Credit Facility was expanded to $900,000,000. The Partnership has the option to request an additional $250,000,000 in revolving commitments with ten 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 credit facility have been met. These amendments did not materially change other terms of the RGS revolving credit facility.

On September 15, 2008, Lehman filed a petition in the United States Bankruptcy Court seeking relief under chapter 11 of the United States Bankruptcy Code. As of December 31, 2008, the Partnership borrowed all but $8,646,000 of the amount committed by Lehman under the Credit Facility. Lehman has declined requests to honor its remaining commitment, effectively reducing the total size of the Credit Facility’s capacity to $891,354,000. Further, if the Partnership makes repayments of loans against the revolving facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed. Further information on the status of Lehman’s commitment is described in Note 16, Subsequent Events.

The outstanding balance of revolving debt under the credit facility bears interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements,

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commitment fees, and amortization of debt issuance costs were 6.27 percent, 8.78 percent and 7.70 percent for the years ended December 31, 2008, 2007, and 2006, respectively. The senior notes bear interest at a fixed rate of 8.375 percent.

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, 2008 and 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;

• 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;

• 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 of $5,626,000 in the year ended December 31, 2006.

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8. Other Assets

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

	Permits and Licenses			Contracts			Trade Names			Customer Relations			Total
	(in thousands)
Balance at January 1, 2007	$	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
Additions		—			64,770			35,100			41,710			141,580
Amortization		(786	)		(6,407	)		(2,252	)		(4,293	)		(13,738	)
Balance at December 31, 2008	$	8,582		$	126,799		$	32,848		$	37,417		$	205,646

The weighted average remaining amortization periods for permits and licenses, contracts, trade names, and customer relations are 10.9, 17.6, 14.1 and 18.3 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is as follows.

Year ending December 31,	Total
	(in thousands)
2009	$	12,453
2010		12,359
2011		11,101
2012		10,808
2013		10,808

Goodwill. Goodwill activity consists of the following.

	Gathering and Processing		Transportation		Contract Compression		Total
Balance at January 1, 2007	$	23,309	$	34,243	$	—	$	57,552
Additions		36,523		—		—		36,523
Balance at December 31, 2007		59,832		34,243		—		94,075
Additions		3,401		—		164,882		168,283
Balance at December 31, 2008	$	63,233	$	34,243	$	164,882	$	262,358

9. Fair Value Measures

On January 1, 2008, the Partnership adopted the provisions of SFAS 157 for financial assets and liabilities. SFAS 157 became effective for financial assets and liabilities on January 1, 2008. On January 1, 2009, the Partnership will apply the provisions of SFAS 157 for non-recurring fair value measurements of non-financial assets and liabilities, such as goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations. SFAS 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations.

SFAS 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

• Level 1—unadjusted quoted prices for identical assets or liabilities in active markets accessible by the Partnership;

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• Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and

• Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

SFAS 157 encourages entities to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities related to interest rate and commodity swaps. Risk management assets and liabilities are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. The Partnership has no financial assets and liabilities as of December 31, 2008 valued based on inputs classified as Level 3 in the hierarchy.

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 approximates 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, 2008 and 2007, 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 $244,887,500 and $367,778,000 as of December 31, 2008 and 2007, respectively.

10. Leases

The Partnership leases office space and certain equipment for various periods and determined that these leases are operating leases. The following table is a schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2008.

For the year ended December 31,	Operating		Capital
	(in thousands)
2009	$	2,357	$	612
2010		2,526		593
2011		2,348		422
2012		1,926		448
2013		1,262		462
Thereafter		5,506		7,562
Total minimum lease payments	$	15,925		10,099
Less: Amount representing estimated executory costs (such as maintenance and insurance), including profit thereon, included in minimum capital lease payments				1,972
Net minimum capital lease payments				8,127
Less: Amount representing interest				4,742
Present value of net minimum capital lease payments			$	3,385

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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, 2008
	(in thousands)
Gross amount included in gathering and transmission systems	$	3,000
Gross amount included in other property and equipment		560
Less accumulated amortization		(421	)
	$	3,139
Current obligation under capital lease	$	535
Noncurrent obligation under capital lease		2,850
	$	3,385

Total rent expense for operating leases, including those leases with terms of less than one year, was $2,576,000, $1,597,000, and $1,721,000 for the years ended December 31, 2008, 2007, and 2006, respectively.

11. Commitments and Contingencies

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. 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 of the FrontStreet gathering system, 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. 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. In 2008, the Partnership was reimbursed for all the remediation work done and pursuant to the C&O Agreement the escrow balance was released to the previous owners.

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

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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 party 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, 2008, $1,510,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and 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 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.

In January 2008, pursuant to authorization by the Board of Directors of the General Partner, the Partnership agreed to settle 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 Partnership-owned facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. In May 2008, the Partnership released all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

Nexus Escrow. At December 31, 2008, $8,521,000 is included in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustments related to the Nexus Acquisition.

Environmental. A Phase I environmental study was performed on certain assets located in west Texas 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 TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”). The NOE alleges that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. On April 3, 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000, and it later reduced its settlement demand to $360,000 in July 2008. The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has referred the matter to its litigation division for further administrative proceedings.

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Contingent Purchase of Sonat Assets. In March of 2008, the Partnership, through the Nexus Acquisition, obtained the rights to a contingent commitment to purchase 136 miles of pipeline that could facilitate the Nexus’ system integration into the Partnership’s north Louisiana asset base. The purchase commitment is contingent upon the FERC declaring that the pipeline is no longer subject to its jurisdiction, together with approval of the current owner’s abandonment and other customary closing conditions. In the event that all contingencies are satisfactorily resolved, the Partnership will pay Sonat $27,500,000. Furthermore, if the closing occurs on or prior to March 1, 2010, the Partnership will pay an additional $25,000,000 to the sellers, subject to certain terms and conditions.

On April 3, 2008, Sonat filed an application with the FERC seeking authorization to abandon by sale to Nexus 136 miles of pipeline and related facilities. The application also requested a determination that the facilities being sold to Nexus be considered non-jurisdictional, with certain facilities being gathering and certain facilities being intrastate transmission. Four producers submitted letters in support of the application and several Sonat shippers protested the application. The matter is currently pending.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the General Partner. Keyes entered into an output contract with the Partnership’s predecessor in 1996 under which it purchased all of the helium produced at the Lakin processing plant in southwest Kansas. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin, as a result of which the Partnership no longer delivered any helium to Keyes. As a result, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium. The Partnership filed an answer to this lawsuit and plans to defend itself vigorously.

Kansas State Severance Tax. In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership. The Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise. The Partnership has requested a determination from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due. If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes for past and future condensate sales.

Purchase Commitments. At December 31, 2008, the Partnership has purchase obligations totaling approximately $323,341,000, of which $104,852,000 relate to the purchase of major compression components unrelated to the Haynesville Expansion Project, that extend until the year ending December 31, 2010 and $218,489,000 of commitments related to the Haynesville Expansion Project that extend until the year ending December 31, 2009. Some of these commitments have cancellation provisions. See Note 16, Subsequent Events, for more information regarding the operating lease facility that we may use to finance the acquisition of compression equipment in 2009.

12. Related Party Transactions

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 term of nine years. TexStar paid $361,000 to HM Capital Partners for the year ended December 31, 2006 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.

BBOG 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

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unrelated third party. BBE is the lessee of office space in the south Texas region where the Partnership subleased offices for which it paid $151,000 and $70,000 in the years ended December 31, 2007 and 2006, respectively.

Concurrent with the TexStar Acquisition, a $600,000 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.

In conjunction with distributions by the Partnership for limited and general partner interests, HM Capital Partners and affiliates received cash distributions of $10,308,000, $24,392,000, and $20,139,000 during the years ended December 31, 2008, 2007, and 2006, respectively, as a result of their ownership interests in the Partnership.

In September 2008, HM Capital Partners and affiliates sold 7,100,000 common units for total consideration of $149,100,000, reducing their ownership percentage to an amount less than ten percent of the Partnership’s outstanding common units. As a result of this sale, HM Capital Partners is no longer a related party of the Partnership.

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. On February 3, 2009, the omnibus agreement expired, with no claims having been filed.

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 $26,899,000, $27,628,000, and $16,789,000 were recorded in the Partnership’s financial statements during the years ended December 31, 2008, 2007, and 2006, respectively, as operating expenses or general and administrative expenses, as appropriate.

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. In the year ending December 31, 2008, three senior management members resigned from their positions, thus effectively reducing management interest in the General Partner to 3.8 percent.

GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $11,746,000 and $7,735,000 to maintain the General Partner’s two percent interest in the Partnership for the years ended December 31, 2008 and 2007, respectively.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS and affiliates received cash distributions of $35,054,000 and $14,592,000 during the year ended December 31, 2008 and 2007, respectively, as result of their ownership interests in the Partnership.

In conjunction with distributions by the Partnership to its limited and general partner interests, certain members of management received cash distributions of $1,887,000 in the year ended December 31, 2008 as a result of their ownership interests in the Partnership.

As part of the August 1, 2008 common units offering, an affiliate of GECC purchased 2,272,727 common units for total consideration of $50,000,000.

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The Partnership’s contract compression segment provides contract compression services to CDM MAX LLC, a related party. The Partnership’s related party receivables and payables as of December 31, 2008 relate to CDM MAX LLC.

13. Concentration Risk

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues and cost of sales from transactions with an 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
	Reportable Segment	December 31, 2008		December 31, 2007		December 31, 2006
		(in thousands)
Customer
Customer A	Transportation		*		*	$	89,736
Supplier
Supplier A	Transportation	$	75,464	$	157,046		*
Supplier A	Gathering and Processing		243,075		*		*
Supplier B	Gathering and Processing		*		*		67,751

* Amounts are less than 10 percent of the total revenues or cost of sales.

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

The Partnership has three reportable segments: i) gathering and processing, ii) transportation and iii) contract compression. 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 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. The Partnership’s 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. The Partnership is responsible for the installation and ongoing operation, service, and repair of our compression units, which are modified as necessary to adapt to customers’ changing operating conditions.

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

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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.

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

	Gathering and Processing		Transportation		Contract Compression		Corporate		Eliminations			Total
	(in thousands)
External Revenue
Year ending December 31, 2008	$	1,205,781	$	525,474	$	132,549	$	—	$	—		$	1,863,804
Year ending December 31, 2007		812,861		377,377		—		—		—			1,190,238
Year ending December 31, 2006		645,770		251,095		—		—		—			896,865
Intersegment Revenue
Year ending December 31, 2008		—		198,294		4,573		—		(202,867	)		—
Year ending December 31, 2007		—		101,734		—		—		(101,734	)		—
Year ending December 31, 2006		—		39,504		—		—		(39,504	)		—
Cost of Sales
Year ending December 31, 2008		949,401		447,313		11,619		—		—			1,408,333
Year ending December 31, 2007		658,100		318,045		—		—		—			976,145
Year ending December 31, 2006		534,398		206,048		—		—		—			740,446
Segment Margin
Year ending December 31, 2008		256,380		78,161		125,503		—		(4,573	)		455,471
Year ending December 31, 2007		154,761		59,332		—		—		—			214,093
Year ending December 31, 2006		111,372		45,047		—		—		—			156,419
Operation and Maintenance
Year ending December 31, 2008		82,689		3,614		49,799		—		(4,473	)		131,629
Year ending December 31, 2007		53,496		4,504		—		—		—			58,000
Year ending December 31, 2006		35,008		4,488		—		—		—			39,496
Depreciation and Amortization
Year ending December 31, 2008		58,900		14,215		28,448		1,003		—			102,566
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
Assets
December 31, 2008		1,054,166		374,659		881,552		148,262		—			2,458,639
December 31, 2007		886,477		329,862		—		62,071		—			1,278,410
Goodwill
December 31, 2008		63,233		34,243		164,882		—		—			262,358
December 31, 2007		59,832		34,243		—		—		—			94,075
Expenditures for Long-Lived Assets
Year ending December 31, 2008		124,736		59,303		186,063		4,981		—			375,083
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

F-39

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

	Year Ended
	December 31, 2008			December 31, 2007			December 31, 2006
	(in thousands)
Net income (loss) from continuing operations	$	101,016		$	(13,836	)	$	(7,244	)
Add (deduct):
Operation and maintenance		131,629			58,000			39,496
General and administrative		51,323			39,713			22,826
Loss on asset sales		472			1,522			—
Management services termination fee		3,888			—			12,542
Transaction expenses		1,620			420			2,041
Depreciation and amortization		102,566			55,074			39,654
Interest expense, net		63,243			52,016			37,182
Loss on debt refinancing		—			21,200			10,761
Other income and deductions, net		(332	)		(1,252	)		(839	)
Income tax expense		(266	)		931			—
Minority interest in net income from subsidiary		312			305			—
Total segment margin	$	455,471		$	214,093		$	156,419

15. Equity-Based Compensation

The Partnership’s LTIP for the Partnership’s employees, directors and consultants covers 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 generally vest on the basis of one-fourth of the award each year. Options expire ten years after the grant date. LTIP compensation expense of $4,318,000, $15,534,000, and $2,906,000 is recorded in general and administrative in the statement of operations for the years ended December 31, 2008, 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. During the year ended December 31, 2008, two former executives of the Partnership exercised 135,000 unit options. Since there were no options granted during the year ended December 31, 2008, the following assumptions apply to the options granted during the years ended December 31, 2007 and 2006.

	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		4.60	%		4.25	%
Weighted average expected volatility		16.0	%		15.0	%
Weighted average expected forfeiture rate		11.0	%		5.0	%

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The common unit options activity for the years ending December 31, 2008, 2007, and 2006 is as follows.

2008
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	738,668		$	21.05
Granted	—			—
Exercised	(245,150	)		20.55		$	1,719
Forfeited or expired	(61,600	)		21.11
Outstanding at end of period	431,918			21.31	7.3		—
Exercisable at the end of the period	431,918						—

2007
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the 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 the end of the period	738,668			21.05			9,104

2006
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	—		$	—
Granted	943,900			21.05
Exercised	—			—
Forfeited or expired	(34,300	)		21.75
Outstanding at end of period	909,600			21.06	9.3	$	5,522
Exercisable at the end of the period	—			—			—

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

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 $14,856,000 of compensation expense related to the grants under LTIP primarily over the next three years.

F-41

The restricted (non-vested) common unit activity for the years ending December 31, 2008, 2007, and 2006 is as follows.

2008
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	397,500		$	31.62
Granted	477,800			27.99
Vested	(90,500	)		31.63
Forfeited or expired	(80,750	)		30.66
Outstanding at the end of period	704,050			29.26
2007
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	516,500		$	21.06
Granted	615,500			30.44
Vested	(684,167	)		22.91
Forfeited or expired	(50,333	)		27.20
Outstanding at the end of period	397,500			31.62
2006
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—		$	—
Granted	516,500			21.06
Vested	—			—
Forfeited or expired	—			—
Outstanding at the end of period	516,500			21.06

16. Subsequent Events

Partner Distributions. On January 27, 2009, the Partnership declared a distribution of $0.445 per common and subordinated unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of $577,000 with respect to incentive distribution rights, payable on February 13, 2009 to unitholders of record at the close of business on February 6, 2009.

On February 9, 2009 and February 17, 2009, 7,276,506 Class D and 19,103,896 subordinated units, respectively, converted into common units on a one for one basis.

Joint Venture Formation. The Partnership, GECC and the Alinda Investors entered into a definitive agreement to form a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas from the Haynesville Shale. In connection with the joint venture, the Partnership will contribute all of its ownership interests in RIGS, with an estimated fair value of $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. GECC and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.

The Partnership will serve as the operator of the joint venture, and will provide all employees and services for the operation and management of the joint venture’s assets. The Partnership expects to close the joint venture transaction as promptly as practicable following the satisfaction of the closing conditions, but no later than April 30, 2009.

F-42

Credit Agreement Amendment. On February 26, 2009, RGS entered into Amendment Agreement No. 7 (the “Amendment”) with Wachovia Bank, National Association, as administrative agent, and the lenders party thereto in order to amend the Credit Agreement. The Amendment will become effective upon the closing of the Contribution Agreement and the satisfaction of certain other conditions precedent.

Upon its effectiveness, the Amendment, among other things, (a) authorizes the contribution by Regency HIG of its ownership interests in RIGS to the joint venture and future investments in the joint venture of up to $135,000,000 in the aggregate, (b) permits distributions by RGS to the Partnership in an amount equal to the outstanding loans, interest and fees under a $45,000,000 revolving credit facility with GECC entered into on February 26, 2009, (c) adds an additional financial covenant that limits the ratio of senior secured indebtedness to EBITDA, (d) provides for certain EBITDA adjustments in connection with the Haynesville Expansion Project, and (e) increases the applicable margins and commitment fees applicable to the credit facility, as further described below.

Upon the effectiveness of the Amendment, (a) the alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent, (b) the applicable margin that is used in calculating interest shall range from 1.50 percent to 2.25 percent for base rate loans and from 2.50 percent to 3.25 percent for Eurodollar loans, and (c) commitment fees will range from 0.375 percent to 0.500 percent.

The Amendment prohibits RGS or its subsidiaries from allowing the joint venture to incur or permit to exist any preferred interests or indebtedness for borrowed money of the joint venture prior to the completion date of the Haynesville Expansion Project. RGS and GECC executed a side letter on February 26, 2009 confirming that, after the closing of the Contribution Agreement, they will not permit their representatives on the management committee of the joint venture to violate such restriction.

Revolving Credit Facility. On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC, as administrative agent, the lenders party thereto and the guarantors party thereto (the “Revolving Credit Facility”). The proceeds of the Revolving Credit Facility may be used for expenditures made in connection with the Haynesville Expansion Project prior to the earlier to occur of the effectiveness of the Amendment and April 30, 2009. The commitments under the Revolving Credit Facility will terminate automatically on the earlier to occur of the effectiveness of the Amendment and April 30, 2009, and the Partnership will be required to prepay all outstanding loans upon the effectiveness of the Amendment. The maturity date under the Revolving Credit Facility will be the earlier of the date that is three months after the final maturity date under the Credit Agreement and November 15, 2011.

Interest will be calculated, at our option, at either (a) the greater of (i) a federal funds effective rate plus 0.50 percent plus the applicable margin or (ii) an adjusted LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent plus the applicable margin and (b) an adjusted LIBOR rate plus the applicable margin. The applicable margin that is used in calculating interest shall range from 3.00 percent to 10.00 percent for base rate loans and from 4.00 percent to 11.00 percent for Eurodollar loans. The Partnership shall pay a 6 percent closing fee. The Partnership shall pay a commitment fee of 0.75 percent per annum on the unused portion of the commitments under the Revolving Credit Facility.

The Partnership is required to comply with the covenants set forth in the Credit Agreement and in the Partnership’s Indenture dated as of December 12, 2006 among us, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee. The Revolving Credit Facility is guaranteed by our subsidiaries (as defined in the Revolving Credit Facility) (other than RIGS, unless the Amendment does not become effective by April 30, 2009).

Lehman Commitments on Revolving Credit Agreement. As of February 20, 2009, the amount of unfunded Lehman commitments has been reduced to $5,578,000 due to other banks in the syndicate increasing their commitments.

F-43

Operating Lease Facility. On February 26, 2009, CDM entered into an operating lease facility with Caterpillar Financial Services Corporation whereby CDM has the ability to lease compression equipment with an aggregate value of up to $75,000,000. CDM paid commitment and arrangement fees of $375,000. As part of the facility, CDM will pay 150 bps on the value of the equipment funded for each lease as funded. The facility is available for leases with inception dates up to and including December 31, 2009, and mitigates the need to use available capacity under the existing Credit Facility. Each compressor acquired under this facility shall have a lease term of one hundred twenty (120) months with a fair value buyout option at the end of the lease term. At the end of the lease term, CDM shall also have an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fair market rate at that time. In the event CDM elects not to exercise the buyout option, the equipment must be returned in a manner fit for use at the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions exist at month sixty (60) and at month eighty four (84) of the one hundred twenty (120) month lease term. Covenants under the lease facility require CDM to maintain certain fleet utilization levels as of the end of each calendar quarter as well as a total debt to EBITDAR (Earnings Before Interest, Taxes, Depreciation, Amortization, and Rental expense) ratio of less than or equal to 4:1. In addition, covenants restrict the concentration of revenues derived from the equipment acquired under the lease facility. The terms of the lease facility do not include contingent rentals or escalation clauses.

F-44

17. Quarterly Financial Data (Unaudited)

Quarter Ended	Operating Revenues		Operating Income (Loss)		Net Income (Loss)			Basic Earnings per Common and Subordinated Unit			Diluted Earnings per Common and Subordinated Unit			Basic and Diluted Earnings per Class B Common Unit		Basic and Diluted Earnings per Class C Common Unit		Basic and Diluted Earnings per Class D Common Unit		Basic and Diluted Earnings per Class E Common Unit
(in thousands except earnings per unit)
2008
March 31(1)	$	405,235	$	25,877	$	10,348		$	0.14		$	0.13		$	—	$	—	$	0.21	$	—
June 30		546,705		26,512		9,972			0.12			0.12			—		—		0.26		—
September 30		547,175		64,956		48,907			0.56			0.53			—		—		0.26		—
December 31		364,689		46,628		31,789			0.39			0.38			—		—		0.26		—
2007(2)
March 31	$	256,428	$	13,480	$	(1,295	)	$	(0.06	)	$	(0.06	)	$	—	$	0.48	$	—	$	—
June 30		302,828		8,768		(7,263	)		(0.16	)		(0.16	)		—		—		—		0.07
September 30		295,825		21,545		(9,833	)		(0.23	)		(0.23	)		—		—		—		0.63
December 31		335,157		15,571		4,555			0.03			0.03			—		—		—		0.53

(1) The operating income amount disclosed above differs immaterially from the amount disclosed in the Form 10-Q.

(2) The quarterly amounts have been recast for the FrontStreet acquisition which was accounted for as an as-if pooling transaction.

F-45

EX-10.7

Exhibit 10.7

AMENDED AND RESTATED

EXECUTIVE EMPLOYMENT AGREEMENT

This AMENDED AND RESTATED EXECUTIVE EMPLOYMENT AGREEMENT is made and entered into as of November 24, 2008, by and between Regency GP LLC, a Delaware limited liability company (together with its successors and assigns permitted hereunder, the “Company”), and Byron R. Kelley (the “Executive”).

WHEREAS, the Company employs Executive on the terms and conditions set forth in an Employment Agreement (the “Agreement”) dated effective April 1, 2008 (the “Effective Date”); and

WHEREAS, the Company and Executive have agreed to make certain modification to the Agreement to comply with the provisions of section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).

NOW, THEREFORE, in consideration of the premises and the mutual covenants set forth below, to avoid adverse tax consequences under section 409A of the Code and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

1. TERM.

Subject to Section 3, the Company hereby agrees to employ Executive, and Executive hereby agrees to be employed by the Company, in accordance with the terms and provisions of this Agreement. The term of this Agreement (the “Term”) shall be the period commencing on the Effective Date and ending on the second anniversary of the Effective Date; provided, however, that commencing on such second anniversary date of the Effective Date, and on each anniversary of such date occurring thereafter, the Term automatically shall be extended for one additional year to the next anniversary of the Effective Date unless at least 365 days prior to the ensuing expiration date, the Company or Executive shall have given written notice to the other that it or he, as applicable, does not wish to extend this Agreement (a “Non-Renewal Notice”). If the Term ends due to a non-renewal, Executive shall continue after such termination as an “at will employee.” Notwithstanding, the foregoing, in the event a Change in Control occurs during the Term, the Term automatically shall be extended to the second anniversary of the effective date of such Change in Control. For purposes of this Agreement, a “Change in Control” means and shall be deemed to have occurred only upon the date that the GE EFS Group ceases to be the “beneficial owner” (as such term is defined in Rule 13d-3 and Rule 13d-5 of the Securities Exchange Act of 1934, as amended), directly or indirectly, of at least 50% of the combined voting power of the then outstanding voting securities of the Company. For purposes of this Agreement, “GE EFS Group” means Regency GP Acquirer L.P., a Delaware limited partnership, Regency LP Acquirer LP, a Delaware limited partnership, and any Person (as defined in Section 9(e)(iv)) that, directly or indirectly, controls Regency GP Acquirer LP or Regency LP Acquirer LP and their respective directors, officers, shareholders, members, managers, representatives of management committees and employees (and members of their respective families and trusts for the primary benefit of such family members).

2. TERMS OF EMPLOYMENT.

(a) Position and Duties.

(i) During the Term, Executive shall serve as the Chief Executive Officer and President of the Company and, in so doing, shall report to the Board of Directors or comparable managing body of the Company (the “Board”). In addition, Executive shall be appointed as a member of the Board and, if elected, serve as the Chairman of the Board. Executive shall have supervision and control over, and responsibility for, such management and operational functions of the Company currently assigned to such positions, and he shall have such other powers and duties as may from time to time be prescribed by the Board, so long as such powers and duties are reasonable and customary for the Chief Executive Officer of an enterprise or division comparable to the Company.

(ii) During the Term, Executive agrees to serve, if elected or appointed to any such positions, as a member of the board of directors of each subsidiary and affiliate of the Company, and as an officer of each subsidiary and affiliate of the Company; provided, however, that Executive is indemnified for serving in any and all such capacities in a manner acceptable to the Company and Executive. Executive agrees that he shall not be entitled to receive any compensation for serving as a member of the Board or as an officer or director of any other Person as provided in this Section 2(a)(ii) other than the compensation to be paid to Executive pursuant to this Agreement or any other written agreement between the Company and Executive.

(iii) During the Term, and excluding any periods of vacation and sick leave to which Executive is entitled and periods of Disability (as defined in Section 3(a)), Executive agrees to devote substantially all of his business time and attention to the business and affairs of the Company and perform his lawful duties and responsibilities in good faith. During the Term, it shall not be a violation of this Agreement for Executive to manage his personal investments, so long as such activities do not materially interfere with the performance of Executive’s duties and responsibilities under this Agreement. Executive agrees that, without the written approval of the Board he shall not serve on the board or committee of any Person (other than charitable non-profit organizations) or engage in any other business activities without the prior consent of the Board, which consent shall not be unreasonably withheld.

(iv) The parties expressly acknowledge that any performance of Executive’s duties and responsibilities hereunder shall necessitate, and the Company shall provide, access to and the disclosure of Confidential Information (as defined in Section 6(a) below) to Executive and that Executive’s duties and responsibilities shall include the development of the Company’s goodwill through Executive’s contacts with the Company’s customers and suppliers. Such access to and disclosure of Confidential Information by the Company to Executive, and such development of goodwill by Executive on behalf of the Company, shall commence immediately upon the Effective Date.

(b) Compensation During the Term.

(i) Base Salary. Executive shall receive an annual base salary (the “Annual Base Salary”), which shall be paid in accordance with the customary payroll practices of the

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Company, at the rate of $475,000 (prorated for any partial calendar year of the Term). The Annual Base Salary shall be reviewed by the Board (or the compensation committee thereof) at least as often as the compensation of other senior executives of the Company is reviewed, and may be increased (but not decreased below the amount set forth in the first sentence of this Section 2(b)(i)) at any time in the sole discretion of the Board (or the compensation committee thereof). Any increase in Annual Base Salary shall not serve to limit or reduce any other obligation to Executive under this Agreement. The term “Annual Base Salary” as utilized in this Agreement shall refer to the Annual Base Salary as then in effect. Notwithstanding anything in this Agreement to the contrary, amounts paid to Executive under the Company’s short-term disability plan or policy shall reduce the amount of Annual Base Salary otherwise then payable to Executive.

(ii) Bonuses. Executive shall be eligible to receive an annual performance bonus (a “Bonus”) in accordance with the annual bonus plan of the Company for executives (the “Bonus Plan”). The Bonus Plan shall have objective performance standards established annually by the Board. Executive has a targeted bonus equal to his Annual Base Salary, if such performance standards are achieved. Without regard to the standards achieved, for the 2008 calendar year Executive shall receive a Bonus of not less than $400,000 and for the 2009 calendar year a Bonus of not less than $200,000. The Bonus shall be payable on the first day of the first calendar month after the determination of the extent to which the Company achieved such performance targets for the calendar year to which the Bonus relates, but not later than the March 15 following the completion of such calendar year.

(iii) Incentive, Savings and Retirement Plans. Executive shall be entitled to participate in all incentive, savings and retirement plans, practices, policies and programs applicable generally to other executives of the Company.

(iv) Welfare Benefit Plans. Executive and Executive’s family shall be eligible to participate in all employee welfare benefit plans, practices, policies and programs provided by the Company to the extent applicable generally to other executives of the Company.

(v) Expenses. Executive shall be entitled to receive prompt reimbursement for all reasonable business expenses incurred by Executive in accordance with the policies, practices and procedures of the Company applicable generally to executives; provided, however, that any such reimbursement shall be made to Executive in compliance with the requirements of Section 2(b)(xi) below.

(vi) Vacation and Holidays. Executive shall be entitled to 27 days of paid vacation time each calendar year (prorated for any partial calendar year of employment), accrued in accordance with the Company’s Paid-Time-Off (“PTO”) policy, in addition to those days designated as paid holidays in accordance with the plans, policies, programs and practices of the Company for its executive officers.

(vii) Perquisites. Executive shall be entitled to receive (in addition to the benefits described above) such perquisites and fringe benefits appertaining to his position in accordance with any practice established by the Board. Executive shall be furnished with all such facilities and services suitable to his position and adequate for the performance of his duties.

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(viii) LTIP Awards. As of the Effective Date, the Board will grant to Executive the following awards under the Regency Gas Long Term Incentive Plan (“LTIP”): a grant of 56,300 Restricted Units substantially in the form of the grant agreement attached hereto as Attachment A; and a grant of 50,000 Restricted Units substantially in the form of the grant agreement attached hereto as Attachment B.

(ix) Additional Award. Upon Executive providing proof from his former employer that, as a result of his resignation from such employer, Executive has forfeited any portion of the benefits he had accrued under his former employer’s Executive Retirement Plan, Supplemental Retirement Plan or Supplemental Savings Plan, the Board will grant to Executive up to an additional 7,500 Restricted Units under the LTIP effective as of April 1, 2008, under the same terms and conditions of this Agreement and Attachment A. The total number of Restricted Units granted pursuant to this Section 2(b)(ix) shall be equal to (a) 7,500, multiplied by (b) a percentage derived by dividing the dollar amount forfeited by Executive at the date of his termination by $225,000.

(x) Allowances and Travel Expenses. The Company shall promptly pay or reimburse Executive, on a grossed-up basis (as provided below), and in compliance with the requirements of Section 2(b)(xi) below, for the following expenses he reasonably incurs in commuting to and from work between Houston and Dallas: (1) the cost of airplane tickets (for travel that is consistent with the Company’s policy) and for the actual vehicle mileage for trips to and from Houston at the Company mileage rate and any direct automobile expenses incurred on such trips, and (2) the cost of staying in a hotel in Dallas (or other similar temporary residence) The reimbursement for the cost of hotel expenses in Dallas shall be limited to a two-month period following the Effective Date. The grossed-up amount shall be determined by dividing actual expenses by a factor of .63. Additionally, the Company shall pay monthly to Executive a monthly living allowance of $4,500, less applicable taxes and withholdings, until the date Executive and his family’s permanent residence is within 50 miles of the Company’s headquarters.

(xi) Reimbursements. Notwithstanding anything to the contrary contained herein, and whether or not this Agreement has been terminated for any reason, any reimbursement by the Company to Executive of any costs and expenses under this Agreement shall be made by the Company upon or as soon as practicable following the receipt of supporting documentation reasonably satisfactory to the Company, but in no event later than the close of Executive’s taxable year following the taxable year in which the cost or expense is incurred by Executive. The expenses incurred by Executive in any calendar year that are eligible for reimbursement under this Agreement shall not affect the expenses incurred by Executive in any other calendar year that are eligible for reimbursement hereunder and Executive’s right to receive any reimbursement hereunder shall not be subject to liquidation or exchange for any other benefit.

(xii) Indemnification/D&O Insurance. Executive shall be indemnified and receive advances of expenses from the Partnership in accordance with Section 7.7 of the

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Agreement of Limited Partnership of Regency Energy Partners LP, and Section 9.1 of the Limited Liability Company Agreement of the Company, each as amended from time to time. The Company shall, or shall cause the Partnership to, maintain D&O Insurance coverage at levels consistent with industry standards.

3. TERMINATION OF EMPLOYMENT.

(a) Death or Disability. Executive’s employment shall terminate automatically upon Executive’s death during the Term. If a Disability occurs during the Term, the Company may give to Executive written notice in accordance with Section 12(b) of its intention to terminate Executive’s employment. In such event, Executive’s employment with the Company shall terminate effective on the 30^th day after such notice is given to Executive (the “Disability Effective Date”), provided that, within the 30 days after such receipt, Executive shall not have returned to the full-time performance of Executive’s duties. For purposes of this Agreement, “Disability” shall mean Executive’s inability to perform his duties and obligations hereunder, with or without reasonable accommodation, for the period contained in the Company’s effective long-term disability plan (“LTD Plan”) and in the event no such LTD Plan exists, such period shall be 180 consecutive days, due to a mental or physical incapacity as determined by a physician mutually selected by the Company and Executive or his representative. Notwithstanding anything in this Agreement to the contrary, in the event of any incapacity or Disability of Executive, the Company may, for the period of such incapacity or Disability, assign Executive’s duties to any other employee of the Company or may engage or hire a third party to perform such duties and any such action shall not be deemed “Good Reason” for Executive to terminate this Agreement pursuant to Section 3(c).

(b) Cause. The Board may terminate Executive’s employment during the Term for Cause or without Cause. For purposes of this Agreement, “Cause” shall mean (i) a breach by Executive of Executive’s obligations under Section 2(a) (other than as a result of physical or mental incapacity or other Disability) which constitutes a material nonperformance by Executive of his obligations and duties under Section 2(a); (ii) commission by Executive of an act of fraud upon, or willful misconduct with respect to, the Company or an affiliate; (iii) a material breach by Executive of Section 6 or a breach by Executive of Section 7, 9 or 11 hereof; (iv) the conviction of Executive of any felony or a misdemeanor involving moral turpitude, or a plea by Executive of other than not guilty to a felony or such a misdemeanor; (v) conduct that results in the Company or any of its affiliates suffering a public disgrace or public disrepute, or (vi) the failure of Executive to carry out, or comply with, in any material respect, any directive (in compliance with law) of the Board consistent with the terms of this Agreement. Notwithstanding the foregoing, no act or omission shall constitute “Cause” for purposes of this Agreement unless the Board provides Executive written notice clearly and fully describing the particular acts or omissions which the Board reasonably believes in good faith constitutes “Cause” and, with respect to acts or omissions in clauses (i) and (vi), Executive fails to remedy such acts or omissions within 10 days of his receipt of such notice. Executive shall have the right to contest a determination of Cause by the Board by requesting arbitration in accordance with the terms of Section 12(h) hereof, but such request shall not affect the Company’s right to terminate or to have terminated Executive’s employment hereunder.

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For purposes of this Agreement, “without Cause” shall mean a termination of Executive’s employment during the Term by the Board for any reason other than a termination for Cause (it being understood that a termination resulting from Executive’s death or Disability shall not constitute a termination “without Cause”).

(c) Good Reason. Executive’s employment may be terminated during the Term by Executive for Good Reason or without Good Reason; provided, however, that Executive may not terminate his employment for Good Reason unless (i) Executive has given the Company prior written notice of his intent to terminate his employment for Good Reason, which notice must be given within 30 days of the event alleged to constitute Good Reason and must specify the facts and circumstances constituting Good Reason, and (ii) the Company has 30 days after its receipt of such notice to remedy the event if and to the extent the event is described under Section 3(c)(i) and (iii). If the Company has not remedied such event constituting Good Reason under Section 3(c)(i) and (iii) by the end of such 30-day period, Executive’s employment shall be terminated by Good Reason on the 31^st day. If the Company timely remedies such event, Executive’s employment shall continue. For purposes of this Agreement, “Good Reason” shall mean:

(i) a material reduction in Executive’s authority, duties or responsibilities as contemplated by Section 2(a), excluding for this purpose (A) an isolated, insubstantial and inadvertent action not taken in bad faith and which is remedied by the Company after receipt of notice thereof given by Executive), (B) any diminution during any period of Executive’s incapacity or Disability, and (C) the failure to elect or re-elect Executive as Chairman of the Board or the removal of Executive as the Chairman of the Board;

(ii) a reduction in Executive’s Annual Base Salary;

(iii) without limiting the foregoing, any other material breach by the Company of a material provision of this Agreement; or

(iv) the relocation of the Company’s corporate office to any location outside of Texas.

(d) Notice of Termination. Any termination by the Company for Cause or without Cause, or by Executive for Good Reason or without Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance with Section 12(b). For purposes of this Agreement, a “Notice of Termination” means a written notice which (i) indicates the specific termination provision in this Agreement relied upon and (ii) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive’s employment under the provision so indicated. The failure by Executive or the Company to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason or Cause shall not waive any right of Executive or the Company hereunder or preclude Executive or the Company from subsequently asserting such fact or circumstance in enforcing Executive’s or the Company’s rights hereunder.

(e) Date of Termination. “Date of Termination” means (i) if Executive’s employment is terminated by his death, the date of his death; (ii) if Executive’s employment is

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terminated by a Disability, as specified in Section 3(a); (iii) if Executive’s employment is terminated by the Company for Cause, then the date specified in the Notice of Termination; (iv) if Executive’s employment is terminated by Executive for Good Reason, as specified in Section 3(c); and (v) if Executive’s employment is terminated for any other reason, the effective date of termination as stated in the Notice of Termination, which shall not be before the expiration of the 60-day period following the date on which the Notice of Termination is given, unless mutually agreed to by the parties. Effective upon his termination of employment for any reason, Executive hereby resigns as an officer and director of the Company and each affiliate for which he may serve as an officer or a director.

4. OBLIGATIONS OF THE COMPANY UPON TERMINATION.

(a) Good Reason; by the Company Other Than for Cause, Death or Disability. If, during the Term, (i) the Company shall terminate Executive’s employment other than for Cause (it being understood that a termination resulting from Executive’s death or Disability shall not constitute a termination “other than for Cause,” which such events are addressed in Section 4(b)) or (ii) Executive shall terminate his employment for Good Reason:

(i) The Company shall pay to Executive (or the executor of his estate or representative, if applicable), within 10 days after the Date of Termination, a lump sum in cash equal to (1) Executive’s Annual Base Salary through the Date of Termination to the extent earned but not yet paid, (2) the unpaid Bonus due Executive, if any, with respect to the calendar year immediately preceding the calendar year in which Executive’s employment is terminated, (3) the value of any vacation accrued, but not taken, in the calendar year in which Executive’s employment is terminated, and (4) the amount due for any reimbursable expenses incurred by Executive prior to the Date of Termination (together, the “Accrued Obligations”).

(ii) The Company shall pay to Executive (or the executor of his estate or representative, if applicable), within the 60-day period provided in Section 4(d) below, a lump sum in cash (less applicable taxes) equal to four times Executive’s Annual Base Salary; provided, however, if the Company, in its sole discretion, elects to waive the non-competition restrictions contained in Section 9(a)(i) through 9(a)(iii) and Section 9(b), the amount to be paid Executive shall be reduced to two times his Annual Base Salary; provided further, however, if Executive’s Date of Termination occurs within three months preceding or on or within two years following a Change in Control, then the amount of severance payable pursuant to this Section 4(a)(ii) shall be four times Executive’s Annual Base Salary, whether or not the Company waives the non-competition restrictions in Section 9 (with respect to a Date of Termination that occurs within the three-month period preceding a Change in Control, if Executive has already been paid pursuant to this Section 4(a)(ii) before the Change in Control occurs and Executive is entitled to an additional amount pursuant to this Section 4(a)(ii), such additional amount shall be paid within 10 days of the Change in Control).

(iii) Subject to Section 4(d), if Executive (and the eligible members of his family) timely elect COBRA continuation coverage, the monthly premium for the first 12 months of such COBRA continuation coverage shall be the monthly premium charged to an active employee for similar coverage.

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(b) Death or Disability. If Executive’s employment is terminated by reason of Executive’s death or Disability during the Term, the Company shall pay to Executive or his legal representatives, as applicable, the Accrued Obligations in a lump sum in cash within 10 days after the Date of Termination and, if such termination is a result of Executive’s Disability, until the earlier of such time as Executive reaches age 65 or dies, if the LTD Plan limits the disability payments to an amount less than 60% of Executive’s Annual Base Salary, the Company shall pay to Executive on a monthly basis the difference between the disability payments Executive actually receives under the LTD Plan and the disability payments Executive would have received thereunder but for such limitation. The Company shall have no further obligations to Executive or his legal representatives under this Agreement.

(c) Cause; by Executive Other than for Good Reason. If, during the Term, the Company terminates Executive’s employment for Cause or Executive terminates his employment without Good Reason, the Company shall have no further obligations to Executive under this Agreement other than for the payment of any Accrued Obligations within 10 days after the Date of Termination.

(d) Release. Notwithstanding anything in this Agreement to the contrary, Executive shall not be entitled to receive the payments provided under Sections 4(a)(ii) and (a)(iii) of this Agreement unless, within 60 days of his Date of Termination, (i) he executes a general release and waiver agreement in a form reasonably acceptable to the Company and (ii) such release has become nonrevocable by Executive.

(e) 409A Delay in Payments. Notwithstanding anything in this Agreement to the contrary, if on the date of Executive’s separation from service Executive is a “specified employee,” as defined in Section 409A of the Code, then all or a portion of any payments, benefits, or reimbursements under this Agreement that would be subject to the additional tax provided by Section 409A(a)(1)(B) of the Code if not delayed as required by Section 409A(a)(2)(B)(i) of the Code shall be delayed until the first business day of the seventh month following his separation from service date (or, if earlier, Executive’s date of death) and shall be paid to Executive in a lump sum (without interest) on such date.

5. FULL SETTLEMENT, MITIGATION.

In no event shall Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to Executive under any of the provisions of this Agreement, and such amounts shall not be reduced whether or not Executive obtains other employment. Neither Executive nor the Company, shall be liable to the other party for any damages in addition to the amounts payable under Section 4 arising out of the termination of Executive’s employment prior to the end of the Term; provided, however, that the Company shall be entitled to seek damages for any breach by Executive of Sections 6, 7, 9 or 11 or his criminal misconduct.

6. CONFIDENTIAL INFORMATION.

(a) Executive acknowledges that the Company and its affiliates have trade, business and financial secrets and other confidential and proprietary information, observations and data,

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including information concerning acquisition opportunities in or reasonably related to the Company’s business of which Executive will become aware during the Term (collectively, the “Confidential Information”). As defined herein, Confidential Information shall not include information that (i) is already in Executive’s possession as of the Effective Date and which information is not known by Executive to be subject to another confidentiality agreement with the Company, (ii) has previously become available in the public domain, (iii) is required to be disclosed pursuant to any applicable state, federal or other laws, including securities laws, or (iv) becomes available to Executive on a non-confidential basis from a source other than the Company, so long as such source is not known by Executive (after reasonable inquiry) to be subject to another confidentiality agreement with the Company.

(b) The Company shall, during the time that Executive is employed by the Company, disclose or entrust to Executive, or provide Executive with access to, or place Executive in a position to create or develop trade secrets or confidential information belonging to the Company; place Executive in a position to develop business goodwill belonging to the Company; and disclose or entrust to Executive business opportunities to be developed for Company.

(c) During his employment with the Company and thereafter, Executive shall (i) hold such Confidential Information in confidence and (ii) not release such information to any Person (other than Company employees and other Persons to whom the Company has authorized Executive to disclose such information and then only within the limits of any authorization for disclosure).

(d) Executive shall not use any Confidential Information for the benefit of any Person other than the Company.

(e) As used in this Section 6, “Company” shall include the Company and any of its direct or indirect subsidiaries and affiliates, including the Partnership.

7. SURRENDER OF MATERIALS UPON TERMINATION.

Upon any termination of Executive’s employment, Executive shall promptly return to the Company all copies, in whatever form, of any and all Confidential Information and other properties of the Company and its affiliates that are in Executive’s possession, custody or control.

8. SUCCESSORS.

(a) This Agreement is personal to Executive and, without the prior written consent of the Company, shall not be assignable by Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by Executive’s legal representatives.

(b) This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns.

(c) The Company may assign its rights hereunder (including the benefit of Executive’s performance hereof) to any successor (whether direct or indirect, by purchase,

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merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company. The Company shall require such successor to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform this Agreement (by express agreement or operation of law) as if no such succession had taken place, and no such assignment of this Agreement or transfer of Executive’s employment in conjunction with such assignment shall constitute a termination of Executive’s employment for purposes of this Agreement or shall entitle Executive to any payments, benefits or other rights under Section 4 (except as specifically provided therein) solely as a result of such assignment or transfer, without prejudice to any other rights or privileges of Executive under this Agreement.

9. NON-COMPETITION AND NON-SOLICITATION.

(a) As part of the consideration for the compensation and benefits to be paid to Executive hereunder and the covenants made by the Company in Sections 2, 4 and 6, to protect the trade secrets and Confidential Information of the Company that have been and will be entrusted to Executive immediately upon commencement of the Term and thereafter, the business goodwill of the Company and its subsidiaries and affiliates that will be developed in and through Executive and/or the business opportunities that will be disclosed or entrusted to Executive by the Company and its subsidiaries and affiliates immediately upon commencement of the Term and thereafter, and as an additional incentive for the Company to enter into this Agreement, from the Effective Date through two years following the Date of Termination (the “Restricted Period”), Executive will not (other than for the benefit of the Company pursuant to this Agreement), and will not permit any member of the Restricted Party Group (as defined in Section 9(e)(v)) to, directly or indirectly, individually or as an officer, director, employee, shareholder, consultant, member, contractor, partner, joint venturer, agent, equity owner or in any capacity whatsoever (including without limitation assisting any other member of the Restricted Party Group to):

(i) conduct, engage in, carry on or assist any other Person in conducting, engaging in or carrying on, in any capacity, any Competing Business (as defined in Section 9(e)(ii).

(ii) induce or attempt to induce any customer, supplier, licensee or other business relation of the Company or any subsidiaries or affiliates of the Company with whom Executive has had direct business contact in dealings during the Term in the course of his employment with the Company, to cease doing business with the Company or any of its subsidiaries or affiliates, or in any way interfere with the relationship between any such customer, supplier, licensee or business relation and the Company or any of its subsidiaries or affiliates;

(iii) own, acquire, attempt to acquire or solicit the acquisition of, directly or indirectly, any equity interest in any Competing Business;

(iv) hire, attempt to hire or contact or solicit with respect to hiring any individual who was an employee of the Company or any of its subsidiaries during the Term; provided, however, that the foregoing clause shall not prohibit (A) any general advertisement or solicitation by Executive that is not directed towards any such employee or group of employees

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of the Company or any subsidiary thereof, (B) Executive from hiring any individual who responds to such general advertisement or solicitation, so long as such individual is not an employee of the Company or any subsidiary thereof at the time such individual responds to such general advertisement or solicitation or (C) Executive from hiring any individual who has not worked for the Company or any of its subsidiaries at any time during the 180-day period immediately preceding the date that Executive hires such individual; or

(v) cause, influence, induce, encourage or attempt to persuade any individual employed by the Company or any subsidiary thereof to terminate his or her employment relationship with the Company or any subsidiary thereof.

(b) Nothing in this Section 9 shall prohibit any investment by Executive or any other member of the Restricted Party Group in securities of any class of the equity securities of a Competing Business, which are regularly traded or quoted on a national securities exchange or an inter-dealer quotation system, provided that the Restricted Party Group directly or indirectly collectively owns no more than 5% of such class of securities, and no member of the Restricted Party Group has the right, through the ownership of an equity interest, voting securities or otherwise, to direct the activities of the Competing Business.

(c) Executive acknowledges that each of the covenants of Sections 9(a)(i) through (vii) are in addition to, and shall not be construed as a limitation upon, any other covenant provided in Section 9(a). Executive agrees that the geographic boundaries, scope of prohibited activities, and time duration of each of the covenants set forth in Sections 9(a)(i) through (v) are reasonable in nature and are no broader than are necessary to maintain the confidentiality and the goodwill of the Company’s Confidential Information, plans and services and to protect the other legitimate business interests of the Company, including the goodwill developed by Executive with the Company’s customers, suppliers, licensees and business partners. Executive further acknowledges that, during the Term, Executive’s engagement hereunder shall necessitate, and the Company will provide, access to or the disclosure of Confidential Information to Executive and/or that Executive’s responsibilities shall include the development of the Company’s goodwill through Executive’s contacts with the Company’s customers, suppliers, licensees and business relations.

(d) The parties hereto intend that the covenants contained in each of Sections 9(a)(i) and (v) be construed as a series of separate covenants, one for each county or other defined province in each geographic area in which the Company conducts its business. Except for geographic coverage, each such separate covenant shall be deemed identical in terms to the applicable covenant contained in Sections 9(a)(i) and (v). Furthermore, each of the covenants in Sections 9(a)(i) through (v) hereof shall be deemed a separate and independent covenant, each being enforceable irrespective of the enforceability (with or without reformation) of the other covenants contained in Sections 9(a)(i) through (v) hereof. In the event that any arbitrator or court of competent jurisdiction shall determine that the scope, time or territorial restrictions set forth in this Section 9 are unreasonable, then it is the intention of the parties that such restrictions be enforced to the fullest extent that the arbitrator or court, as applicable, deems reasonable and the Agreement shall thereby be reformed.

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(e) For purposes of this Agreement:

(i) “affiliate” means, with respect to any Person, each other Person that directly or indirectly (through one or more intermediaries or otherwise) controls, is controlled by or is under common control with such Person. The term “control” (including the terms “controlled by” and “under common control with”) means the possession, directly or indirectly, of the actual power to direct or cause the direction of the management policies of a Person, whether through the ownership of stock, by contract, credit arrangement or otherwise.

(ii) “Competing Business” means any activity that is directly or indirectly competitive with the business of the Company or any of its subsidiaries or affiliates as conducted during the Term on or with respect to the Lands;

(iii) “Lands” means (a) when used with respect to any action during the Term, each and every county, parish or analogous geographic area in the United States in which the Company or any of its subsidiaries or affiliates is conducting business at the time of any action in question arising under this Section 9, and (b) when used with respect to any action after the Date of Termination, each and every county, parish or analogous geographic area in the United States in which the Company or any of its subsidiaries or affiliates (i) was conducting business or (ii) with respect to which (1) the Board or management of the Company or its subsidiaries or Affiliates was actively considering commencing conducting business and (2) Executive was involved in planning the Company’s entry, or the entry of any of its subsidiaries or affiliates, into those geographic areas or jurisdictions), as of the Date of Termination;

(iv) “Person” means an individual or a corporation, partnership, limited liability company, trust, joint venture, unincorporated organization, association or other entity; and

(v) “Restricted Party Group” means Executive, together with (A) the Executive’s immediate family members and (B) any Business Enterprise in which Executive and/or any of Executive’s immediate family members collectively own or have the right to acquire an equity interest in excess of 5% or otherwise have any right, through the ownership of a voting interest or otherwise, to direct the activities of such Business Enterprise.

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10. EFFECT OF AGREEMENT ON OTHER BENEFITS.

Nothing in this Agreement shall prevent or limit Executive’s continuing or future participation in any benefit, plan, program, policy or practice provided by the Company and for which Executive may qualify, nor shall anything herein limit or otherwise adversely affect such rights as Executive may have under any other contract or agreement entered into after the Effective Date with the Company. Amounts which are vested benefits or which Executive is otherwise entitled to receive under any benefit, plan, policy, practice or program of, or any contract or agreement entered into with the Company shall be payable in accordance with such benefit, plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement.

11. NO PRIOR AGREEMENTS.

Executive hereby represents and warrants to the Company that the execution of this Agreement by Executive and his employment by the Company and the performance of Executive’s duties hereunder will not violate or be a breach of any agreement, obligation or contract between Executive and a former employer or any other Person. Further, Executive agrees to indemnify the Company for any claim, including attorneys’ fees and expenses of investigation, by any such Person that such Person may now have or may hereafter come to have against the Company based upon or arising out of any noncompetition agreement, invention or secrecy agreement between Executive and such Person which was in existence as of the Effective Date. For purposes of clarity, this Agreement does not require or obligate Executive in any way to disclose or use for the benefit of the Company, any information that would result in the breach or violation of any agreement with a former employer and Executive covenants that he will not breach or violate any such agreement.

12. MISCELLANEOUS.

(a) Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas without reference to principles of conflict of laws.

(b) Notices. All notices, requests, claims, demands and other communications hereunder shall be in writing and shall be given by hand delivery, or by mail (registered or certified mail, postage prepaid, return receipt requested) or by any nationally recognized overnight courier service, providing proof of delivery. All communications hereunder shall be delivered to the respective parties at the following addresses:

If to Executive:

Byron R. Kelley

at his most recent address

in the records of the Company

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With a copy (which shall not constitute notice) to:

Gardere Wynne Sewell LLP

1601 Elm Street

Suite 3000

Dallas, TX 75201

Attn: Alan J. Perkins

If to the Company:

Regency Gas Services LLC

1700 Pacific, Suite 2900

Dallas, TX 75201

Attn: General Counsel

or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice, requests, claims, demands and other communications shall be deemed to have been received (i) the same day as sent if given by hand delivery, (ii) five business days after sent if given by mail (registered or certified mail, postage prepaid, return receipt requested) and (iii) the next business day after sent if given by a nationally recognized overnight courier.

(c) Severability. In the event that any provision of this Agreement, or the application thereof to any Person or circumstance, is held by a court of competent jurisdiction to be invalid, illegal, or unenforceable in any respect under present or future laws effective during the effective term of any such provision, such invalid, illegal or unenforceable provision shall be fully severable, this Agreement shall then be construed and enforced as if such invalid, illegal, or unenforceable provision had not been contained in this Agreement, and the remaining provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance from this Agreement. Furthermore, in lieu of each such illegal, invalid, or unenforceable provision, there shall be added automatically as part of this Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable. Notwithstanding the above, in the event any such invalidity, illegality or unenforceability of any portion of Section 9(a) is caused by such provision being held to be excessively broad as to time, duration, geographical scope, activity or subject in any jurisdiction, then such provision shall, at the option of the Company, remain a part of this Agreement and shall be reformed and construed within such jurisdiction by limiting and reducing it so as to be enforceable to the extent compatible with then applicable law.

(d) Tax Withholding. The Company may withhold from any amounts payable under this Agreement such federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation.

(e) Amendment; Waiver. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives. Executive’s or the Company’s failure to insist upon strict

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compliance with any provision of this Agreement, or the failure to assert any right Executive or the Company may have hereunder, shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement.

(f) Entire Agreement. The provisions of this Agreement and the grants of Restricted Units attached hereto constitute the complete understanding and agreement between the parties with respect to the subject matter hereof and this Agreement supersedes all other agreements (written or oral) and understandings prior to or contemporaneous with this Agreement pertaining to the subject matter hereof.

(g) Counterparts. This Agreement may be executed in two or more counterparts.

(h) Arbitration. The Company and Executive agree to the resolution by binding arbitration of all claims, demands, causes of action, disputes, controversies or other matters in question (“claims”) arising out of this Agreement or Executive’s employment (or its termination), whether in contract, tort or otherwise and whether provided by statute or common law, that the Company may have against Executive or that Executive may have against the Company or its parents, subsidiaries and affiliates, and each of the foregoing entities’ respective officers, directors, employees or agents in their capacity as such or otherwise; except that this agreement to arbitrate shall not limit the Company’s right to seek equitable relief, including injunctive relief and specific performance, as provided in Section 12(i). Notwithstanding the foregoing, however, this Section 12(h) shall not apply in the event Executive asserts any claim arising under or related to ERISA. The arbitrator may make an interim award granting equitable relief to either party and such award may be enforced like a final award. Claims covered by this agreement to arbitrate also include claims by Executive for breach of this Agreement or other claims arising out of his employment, including but not limited to, wrongful termination, discrimination (based on age, race, sex, disability, national origin, religion or any other factor), statutory leave entitlements and retaliation. The Company and Executive agree that any arbitration shall be in accordance with the Federal Arbitration Act (“FAA”) and, to the extent an issue is not addressed by the FAA, with the then-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association (“AAA”) or such other rules of the AAA as applicable to the claims being arbitrated. The arbitration shall be conducted by a single arbitrator, who shall be selected by agreement of the parties or if they do not agree on an arbitrator within 15 days after either the Company or Executive has made a demand for arbitration then the arbitrator will be selected pursuant to the rules of the AAA. If a party refuses to honor its obligations under this Agreement to arbitrate, the other party may compel arbitration in either federal or state court. The arbitrator shall apply the substantive law of the State of Texas (excluding Texas choice-of-law principles that might call for the application of some other state’s law), or federal law, or both as applicable to the claims asserted. The arbitrator shall have exclusive authority to resolve any dispute relating to the interpretation, applicability, enforceability or formation of this Agreement to arbitrate, including any claim that all or part of this Agreement is void or voidable and any claim that an issue is not subject to arbitration. The parties agree that the exclusive venue for arbitration will be in the county in which the Company’s headquarters are then located, and that any arbitration commenced in any other venue will be transferred to such county upon the written request of any party to this Agreement. If permitted by law, the party in whose favor the arbitrator renders the award may, in the discretion of the arbitrator, also be awarded all costs and expenses actually incurred, including

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reasonable attorneys’ fees, and costs, but excluding expert witness fees. Any and all of the arbitrator’s orders, decisions and awards may be enforceable in, and judgment upon any award rendered by the arbitrator may be confirmed and entered by, any federal or state court having jurisdiction. All proceedings conducted pursuant to this agreement to arbitrate, including any order, decision or award of the arbitrator, shall be kept confidential by all parties except to the extent such disclosure is required by law, or in a proceeding to enforce the rights hereunder. THE PARTIES ACKNOWLEDGE THAT, BY SIGNING THIS AGREEMENT, THEY ARE WAIVING ANY RIGHT THAT THEY MAY HAVE TO A JURY TRIAL OR A COURT TRIAL OF ANY EMPLOYMENT-RELATED CLAIM.

(i) Specific Enforcement. Executive acknowledges that the covenants of Executive contained in Sections 6 and 9(a) of this Agreement are special and unique, that a breach by Executive of any term or provision of either of Sections 6 or 9(a) hereof may cause irreparable injury to the Company and/or other affiliates of the Company, and that remedies at law for the breach of any terms or provisions of Sections 6 or 9(a) hereof may be inadequate. Accordingly, notwithstanding the provisions of Section 12(h), in addition to any other remedies it may have in the event of breach, the Company shall be entitled to enforce specific performance of the terms and provisions of Sections 6 or 9(a) hereof, to obtain temporary and permanent injunctive relief to prevent the continued breach of such terms and provisions without the necessity of posting a bond or of proving actual damage. The party prevailing in any such action shall be entitled to be reimbursed by the other party for reasonable attorney fees incurred in respect of the foregoing. For purposes of this Section 12(i) and Sections 6 and 9(a) hereof, each affiliate of the Company shall be deemed a third party beneficiary entitled to the benefits of such Sections and shall be entitled to enforce Sections 6 and 9(a) of this Agreement in accordance with this Section 12(i).

(j) Survival. Sections 4, 5, 6, 7, 8, 9, 11 and 12 of this Agreement shall survive the termination of Executive’s employment during the Term.

(k) Interpretation. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect. Whenever the terms “hereof”, “hereby”, “herein”, or words of similar import are used in this Agreement they shall be construed as referring to this Agreement in its entirety rather than to a particular section or provision, unless the context specifically indicates to the contrary. Any reference to a particular “Section” or “paragraph” shall be construed as referring to the indicated section or paragraph of this Agreement unless the context indicates to the contrary. The use of the term “including” herein shall be construed as meaning “including without limitation.”

[signature page follows]

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IN WITNESS WHEREOF, Executive has hereunto set his hand and, pursuant to the authorization from the Board, the Company has caused this Agreement to be executed in its name on its behalf, all as of the Effective Date.

EXECUTIVE
/s/ Byron R. Kelley
Byron R. Kelley
REGENCY GP LLC
By:	/s/ Dan Fleckman
	Name:	Dan Fleckman
	Title:	Executive Vice President Chief Legal Officer

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EX-10.9

Exhibit 10.9

AMENDED AND RESTATED

EMPLOYMENT AGREEMENT

This AMENDED AND RESTATED EMPLOYMENT AGREEMENT is effective as of December 2, 2008 by and between Randall Dean (“Executive”) and Regency GP LLC (the “Managing General Partner”), the managing general partner of the general partner of Regency Energy Partners LP (the “Partnership”).

WHEREAS, ADJHR, LLC (the “Company”) is an indirect wholly-owned subsidiary of the Partnership; and

WHEREAS, the Managing General Partner employs Executive to serve as its employee and to serve as the President and Chief Executive Officer of the Company;

WHEREAS, the Managing General Partner and Executive entered into an Employment Agreement dated effective January 15, 2008 (the “Agreement”); and

WHEREAS, the Managing General Partner and Executive have agreed to make certain modifications to the Agreement to comply with the provisions of section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).

NOW, THEREFORE, in consideration of the premises and the mutual covenants set forth below, to avoid adverse tax consequences under section 409A of the Code and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

1. Employment. The Managing General Partner hereby agrees to employ Executive to serve as its employee and to serve as the President and Chief Executive Officer of the Company, and Executive hereby accepts such employment, on the terms and conditions hereinafter set forth.

2. Term. The period of employment of Executive by the Managing General Partner under this Agreement (the “Employment Period”) shall commence on January 15, 2008 (the “Commencement Date”) and shall continue through the third anniversary thereof.

3. Position and Duties. During the Employment Period, Executive shall serve as the President and Chief Executive Officer of the Company, and shall report to the Chief Executive Officer (or, if there is no Chief Executive Officer, the highest-level executive officer) of the Managing General Partner. Executive shall have those powers and duties with respect to the Company normally associated with the position of President and Chief Executive Officer, and such other powers and duties as may be assigned to him by the Board of Directors of the Managing General Partner (hereinafter referred to as “Board”); provided that, the Board shall assign him only such other powers and duties as are of a type, nature and dignity consistent with Executive’s position, and do not violate any applicable laws or regulations. Subject to the remaining provisions hereof, Executive shall devote his full working time, attention and energies to the performance of his duties for the Managing General Partner. Executive shall retain the ability, without violating the terms of employment with the Company or the Partnership’s

conflict of interest policies, to (i) have an indirect economic interest in CDM MAX, LLC, a Texas limited liability company (“CDM MAX”), (ii) have board-level involvement with the operations and affairs of CDM MAX, provided that such involvement does not significantly interfere with Executive’s duties to the Company, and (iii) receive payments related to CDM MAX, both in respect of the indirect ownership position and consulting fees disclosed to the Managing General Partner; provided, however, that Executive may not cause CDM MAX to solicit customers of the Partnership or any of its Subsidiaries in areas in which CDM MAX may become competitive with the Partnership or any of its Subsidiaries. Executive may also manage personal investments and engage in civic or charitable activities so long as the same do not interfere with the performance of Executive’s responsibilities as an employee of the Managing General Partner in accordance with this Agreement. If, from time to time, the Company or an Affiliate of the Company desires that the Executive render services to any such Affiliate outside the scope of the services described above, then (i) the Company shall first obtain authorization from the Chief Executive Officer (or, if there is no Chief Executive Officer, the highest-level executive officer) of the Managing General Partner and (ii) any additional compensation to Executive for providing those services must be reasonably acceptable to Executive.

4. Place of Performance. The place of employment of Executive shall be at the Company’s principal executive offices in Houston, Texas, or at such other offices as the Board may designate; provided, that, Executive shall not be required to relocate outside of the Greater Houston Metropolitan Area. Executive acknowledges that he may be required to travel on Company business during the Employment Period.

5. Compensation and Related Matters.

(a) Base Salary. During the Employment Period, the Managing General Partner shall pay Executive a base salary at the rate of not less than $316,900 per year (“Base Salary”). Executive’s Base Salary shall be paid in accordance with the Managing General Partner’s customary payroll practices. The Compensation Committee of the Board shall annually review Executive’s Base Salary for increase (but not decrease), consistent with the compensation practices and guidelines of the Managing General Partner. If Executive’s Base Salary is increased by the Managing General Partner, such increased Base Salary shall then constitute the Base Salary for all purposes of this Agreement.

(b) Bonuses. During each full or partial fiscal year of the Managing General Partner that occurs during the Employment Period, Executive shall be eligible for an annual performance bonus (the “Bonus”), to be awarded and determined at the sole discretion of the Board or its Compensation Committee, of up to 100% of Executive’s then current Base Salary. The Bonus, if any, may be payable in cash, equity, or some combination thereof, at the discretion of the Board or such Compensation Committee. Any Bonus earned during a fiscal year shall be paid at such time as the Managing General Partner customarily pays annual bonuses; provided, that, Executive is still employed as of such date, but in no event later than the 90th day of the year following the fiscal year in which the Bonus is earned.

(c) Expenses. During the Employment Period, the Managing General Partner shall promptly reimburse Executive for all reasonable business expenses upon the presentation of reasonably itemized statements of such expenses in accordance with the Managing General

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Partner’s generally applied policies and procedures now in force which provide an objectively determinable nondiscretionary definition of the expenses eligible for reimbursement, or as such policies and procedures may be modified with respect to all executive officers of the Managing General Partner. Notwithstanding any provision of this Agreement to the contrary, the amount of expenses for which Executive is eligible to receive reimbursement during any calendar year shall not affect the amount of expenses for which Executive is eligible to receive reimbursement during any other calendar year within the Employment Period. In addition, any reimbursement of expenses provided for in this Agreement shall be made on or before the last day of the calendar year following the calendar year in which the expense was incurred. Executive is not permitted to receive a payment or other benefit in lieu of reimbursement under Section 5(c).

(d) Vacation. During the Employment Period, Executive shall be entitled to the maximum amount of paid time off (including vacation, sick days and personal time) permitted to employees of the Managing General Partner in accordance with the Managing General Partner’s generally applied policy as it may be established from time to time (assuming more than ten years’ credited service by Executive. In addition to vacation, Executive shall be entitled to the number of national holidays per year that other executive officers of the Managing General Partner with similar tenure are entitled under the Managing General Partner’s policies.

(e) Welfare, Pension and Incentive Benefit Plans and Perquisites. During the Employment Period, Executive shall be entitled to participate in such employee benefit plans offered by the Managing General Partner, or that it may adopt from time to time, for its executives, in accordance with the eligibility requirements for participation therein and the other terms and conditions thereof.

(f) Equity Awards. During each fiscal year of the Company that occurs during the Employment Period, Executive shall be eligible to receive such equity awards (which may include Class C Common Units of Regency GP Acquirer LP) as the Board, or its Compensation Committee, may, in its sole discretion, choose to award to him.

(g) Indemnification and Insurance. Executive shall be entitled to insured status under the Managing General Partner’s Directors & Officers Liability Insurance to the same extent that its other executive officers are insureds. In addition, at or about the time of the execution of this Agreement, Executive and the Managing General Partner shall enter into an indemnification agreement in substantially the form entered into and in effect with the Managing General Partners’ executive officers.

6. Termination Procedure.

(a) Right and Notice of Termination. Any party may terminate the employment relationship with or without cause or good reason. Any termination during the Employment Period (other than termination by death) shall be communicated by written Notice of Termination to the other party hereto in accordance with Section 10.

(b) Date of Termination. “Date of Termination” shall mean (i) if Executive’s employment is terminated by his death, the date of his death, or (ii) if Executive’s employment is terminated pursuant to notice, the date the Notice of Termination is provided to the other party,

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provided, that, if applicable, the Notice of Termination shall not be effective until any applicable cure period has expired and such event or events leading to such termination have not yet been cured.

(c) Consequences of Termination by Managing General Partner Without Cause or by Executive For Good Reason. Should the employment relationship be terminated: (i) by the Managing General Partner without Cause; or (ii) by the Executive for Good Reason, then the Executive shall be entitled to:

• payment of accrued and unpaid Base Salary and unused vacation time accrued through the Date of Termination, to be paid in a lump sum immediately upon Executive’s Date of Termination, but in no event later than 74 days thereafter;

• payment of any deferred compensation accrued through the Date of Termination, to be paid in accordance with the terms and conditions of the applicable plan;

• payment of a lump-sum amount equal to one year of Executive’s Base Salary to be paid to Executive immediately upon Executive’s Date of Termination, but in no event later than 74 days thereafter; provided, however, that, in case of a termination by Executive for Good Reason based on an Interference Item (as defined below), then the payment under this bullet-point paragraph shall be made, rather than to the Executive, into a bonus pool arrangement for the benefit of the Company’s employees, to be paid to them, as determined by the Compensation Committee of the Board, over and above the compensation they would otherwise receive, under a written arrangement in which the Executive can be reasonably assured of such payment into such pool for the benefit of such employees, which shall be implemented within 90 days following the Date of Termination or, if not so timely implemented, then such lump-sum payment shall be paid into a pool under Executive’s control who shall implement such pool for the benefit of such employees;

• payment of the Bonus for the fiscal year of termination based upon the maximum target Bonus level for such year, prorated on a per day basis from the first date of such fiscal year through the Date of Termination, based on a calendar year of 365 or 366 days, as the case may be, to be paid immediately following the end of the fiscal year for which such Bonus relates, but in no event later than 74 days thereafter;

• continuation of group health coverage, at the Managing General Partner’s expense, for the Executive and his spouse and dependents for a period of 36 months following the Date of Termination, or until the Executive and his spouse and dependents become eligible under another employer’s health coverage (whichever is sooner); and

• notwithstanding anything to the contrary in any option or restricted unit agreement, accelerated vesting to the Date of Termination of all outstanding options and restricted units as well as an extension of the period during which an award may be exercised to one year after the Date of Termination.

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(d) Consequences of Termination by Managing General Partner For Cause or by Executive Without Good Reason. Should the employment relationship be terminated: (i) by the Managing General Partner for Cause; or (ii) by the Executive without Good Reason, then:

• the Executive shall be entitled only to payment of accrued and unpaid Base Salary through the Date of Termination, to be paid in a lump sum immediately upon Executive’s Date of Termination, but in no event later than 74 days thereafter; and

• the Executive shall automatically forfeit all deferred compensation, unused vacation time, unpaid Bonuses, unredeemed equity awards, and other compensation, whether vested or unvested (except for vested 401(k) and retirement benefits).

(e) Definition of Cause For Termination. The Managing General Partner shall have “Cause” for termination of the employment relationship with Executive only upon any of the following to occur:

• Executive’s conviction of, or a plea of nolo contendere to, a crime that constitutes a felony;

• Executive’s breach of his confidentiality or non-compete obligations under paragraph (b) or (c) of Section 7;

• Determination by a court of competent jurisdiction that Executive has breached his fiduciary duty of loyalty, due care or good faith, as such terms are understood and applied to officers of business entities under Delaware law, to the Company or to the Managing General Partner;

• Executive’s willful or gross neglect of his duties;

• Executive’s commission of a material act of fraud or willful misconduct with respect to the performance of his duties;

• Executive’s misappropriation of funds or property of the Partnership;

• Executive’s knowing engagement, without the express written consent of the Managing General Partner or except as regarding CDM MAX in accordance with Section 3, in any activity that competes with or is materially injurious to the business or reputation of the Partnership; or

• Executive’s material breach of the material terms of this Agreement.

(f) Definition of Good Reason For Termination. Executive shall have “Good Reason” for termination of the employment relationship with the Managing General Partner upon any of the following to occur:

• So long as Executive is able to perform his duties specified under Section 3 hereof, a material change in Executive’s position or duties that is not agreed to in writing by Executive;

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• The Managing General Partner’s failure to cure a material breach by the Managing General Partner of the terms of this Agreement; or

• Any (1) changes (subject to the penultimate sentence of this bullet point paragraph) in the Company’s key executive personnel (vice president and above), or material adverse change in their terms of employment, including salary or medical benefits, (2) material change in the business method by which the Company performs contract compression services, (3) cessation of the Company’s quarterly bonus program for employees below the executive management team, or any change in such program (other than the amount thereof) that is materially adverse to such employees, or (4) relocation of the Company’s corporate office; provided, however, that the items described in this bullet-point paragraph (“Interference Items”) shall no longer apply if, for any budget year (currently the calendar year), beginning with the year ending December 31, 2008, the Company’s actual revenue is more than 10% less than the budgeted revenue established at the beginning of that year, as then approved by the Board. It shall not constitute “Good Reason” under clause (1) if a change in personnel occurs as the result of the death or disability or voluntary resignation of any such personnel, provided that Good Reason shall exist if the replacement of any such personnel is not designated by or reasonably acceptable to the Executive. It shall not constitute “Good Reason” under any such clause if the change or relocation is initiated or approved in writing by the Executive;

provided that, with respect to any of the above conditions, (i) Executive has provided the Managing General Partner written notice of the existence of such condition, which notice must be given within 90 days of the initial existence of such condition, and (ii) the Managing General Partner has 30 days after the giving of such notice to remedy such condition.

7. Restrictive Covenants.

(a) Acknowledgments. Executive acknowledges that: (i) as a result of Executive’s employment by the Managing General Partner and by the Company’s predecessor, Executive has obtained and will obtain Confidential Information (as defined below); (ii) the Confidential Information has been developed and created by the Company and the Regency Affiliates at substantial expense, and the Confidential Information constitutes valuable proprietary assets; (iii) the Company and the Regency Affiliates may suffer substantial damage and irreparable harm that will be difficult to compute if, during the Employment Period and thereafter, Executive should enter a Competitive Business (as defined herein) in violation of the provisions of this Agreement; (iv) the nature of the Company’s and the Regency Affiliates’ business is such that it could be conducted any where in the world and that it is not limited to a geographic scope or region; (v) the Company and the Regency Affiliates may suffer substantial damage that will be difficult to compute if, during the Employment Period or thereafter, Executive should solicit or interfere with the Company’s or any Regency Affiliate’s employees,

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clients or customers or should divulge Confidential Information relating to the business of the Company or any such Regency Affiliates; (vi) the provisions of this Agreement are reasonable and necessary for the protection of the business of the Company and the Regency Affiliates; (vii) in granting the benefits to Executive under this Agreement, the Managing General Partner is relying on Executive’s agreement to be bound by the terms hereof; and (viii) the provisions of this Agreement will not preclude Executive from other gainful employment. “Competitive Business” as used in this Agreement shall mean any business that competes, directly or indirectly, with the business of the Company, the Partnership and its other Subsidiaries as conducted on the date of this Agreement. “Confidential Information” as used in this Agreement shall mean any and all confidential and/or proprietary knowledge, data, or information of the Partnership and its Subsidiaries, including, without limitation, any: (A) trade secrets, drawings, inventions, methodologies, mask works, ideas, processes, formulas, source and object codes, data, programs, software source documents, works of authorship, know-how, improvements, discoveries, developments, designs and techniques, and all other work product of the Partnership or any of its Subsidiaries, whether or not patentable or registrable under trademark, copyright, patent or similar laws; (B) information regarding plans for research, development, new service offerings and/or products, marketing, advertising and selling, distribution, business plans, business forecasts, budgets and unpublished financial statements, licenses, prices and costs, suppliers, customers or distribution arrangements; (C) any information regarding the compensation of employees, suppliers, agents, and/or independent contractors of the Partnership or any of its Subsidiaries; (D) concepts and ideas relating to the development and distribution of content in any medium or to the current, future and proposed products or services of the Partnership or any of its Subsidiaries; or (E) any other information, data or the like that is labeled confidential or orally disclosed to Executive as confidential. As defined herein, Confidential Information shall not include information that (i) is in or becomes released into the public domain other than as a result of Executive’s breach of any of obligations hereunder, (ii) is required to be publicly disclosed pursuant to any applicable state, federal or other laws, including securities laws, or (iii) becomes available to Executive on a non-confidential basis from a source other than the Company, the Partnership or another Subsidiary thereof, so long as such source is not known by Executive (after reasonable inquiry) to be subject to another confidentiality agreement with the Company, the Partnership or such other Subsidiary. “Subsidiary” as used in this Agreement shall mean, with respect to any Person, any corporation or other organization (including a limited liability company or a partnership), whether incorporated or unincorporated, of which such Person directly or indirectly owns or Controls at least 50% of the securities or other interests having by their terms ordinary voting power to elect at least 50% of the board of directors or others performing similar functions with respect to such corporation or other organization or any organization of which such Person is a general partner or managing partner. “Affiliate” as used in this Agreement shall mean, with respect to any Person, any other Person that directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with, the first mentioned Person. “Regency Affiliates” means, collectively, the Partnership and all Subsidiaries thereof other than the Company. “Person” as used in this Agreement shall mean any individual, corporation, partnership, limited liability company, association, trust, incorporated organization, other entity or group (as defined in Section 13(d)(3) of the Securities Exchange Act of 1934, as amended). “Control”, and its derivative expressions, as used in this Agreement shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

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(b) Confidentiality. In consideration of the benefits provided for in this Agreement, Executive agrees that he will not, at any time, either during the Employment Period or thereafter, divulge, publish or in any other manner disclose, directly or indirectly, to any Person any, and agrees to keep in the strictest confidence all, Confidential Information, except (i) as may be necessary to the performance of Executive’s duties hereunder, (ii) with the Managing General Partner’s express written consent, or (iii) where required to be disclosed by court order, subpoena or other government process and, in such event, Executive shall reasonably cooperate with the Managing General Partner to the extent he may lawfully do so in attempting to keep such information confidential. Upon termination, Executive agrees to promptly deliver to the Managing General Partner the originals and all copies, in whatever medium, of all such Confidential Information.

(c) Non-Compete. In consideration of the benefits provided for in this Agreement, and to protect the Confidential Information to be provided to him, Executive covenants and agrees that during his employment and for a period of three years following the termination of his employment for whatever reason (the “Restricted Period”), he will not, in those geographic areas in which the Partnership or any of its Subsidiaries actively conduct business as of the date of this Agreement or within the preceding six months, for himself, or in conjunction with any other Person (whether as a shareholder, partner, member, principal, agent, lender, director, officer, manager, trustee, representative, employee or consultant), directly or indirectly, be employed by, provide services to, in any way be connected, associated or have any interest in, or give advice or consultation to (in each case whether for pay or otherwise) any Competitive Business without the Managing General Partner’s prior written consent except (i) as specifically contemplated by, and in accordance with, Section 3 as it relates to CDM MAX, and (ii) any investment by Executive in the publicly traded securities of any business entity constituting less than one percent (1%) of the securities of such class outstanding at the time any determination is made under this clause (ii). Should Executive be determined by a final, non-appealable judgment of a court of competent jurisdiction to have breached the foregoing non-compete obligation, the Restricted Period shall be extended for the term of the breach as found by such court.

(d) Non-Solicitation of Employees. In consideration of the benefits provided for in this Agreement, Executive covenants and agrees that during the Restricted Period, he will not, for himself or any other Person, directly or indirectly (i) solicit or employ, or have or cause any other Person to solicit or employ, any individual who is employed by the Partnership or any of its Subsidiaries at the Date of Termination or (ii) request, cause or encourage any employee of the Managing General Partner, the Partnership or any of its Subsidiaries to breach or threaten to breach any terms of said employee’s agreements with the Partnership or any of its Subsidiaries or to terminate his or her employment with the Managing General Partner, the Partnership or any of its Subsidiaries. Should Executive be determined by a final, non-appealable judgment of a court of competent jurisdiction to have breached the foregoing non-solicitation obligation, the Restricted Period shall be extended for the term of the breach as found by such court. For the absence of doubt, Executive’s activities as specifically contemplated by, and in accordance with, Section 3 as it relates to CDM MAX, shall not constitute a violation of this paragraph (d) or paragraph (e) below.

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(e) Non-Solicitation of Clients, Customers and Contact Sources. In consideration of the benefits provided for in this Agreement, Executive covenants and agrees that during the Restricted Period, he will not, for himself or any other Person, directly or indirectly: (i) solicit or accept any business of the type engaged in by the Company, the Partnership or any of its other Subsidiaries, from any person or entity who, at the time of, or at the time during the 12 months preceding, the Date of Termination, was an existing customer, client or contact source of the Partnership or any of its Subsidiaries; or (ii) cause any of such clients, customers or contact sources of the Partnership or any of its Subsidiaries to cancel or terminate any business relationship with the Partnership or any of its Subsidiaries involving services or activities that were directly or indirectly the responsibility of Executive during his employment; except in any such case on behalf of the Company, the Partnership or another Subsidiary in carrying out the Executive’s duties hereunder.

(f) Enforcement. If Executive commits a breach, or overtly threatens to commit a breach, of any of the provisions of this Section 7, the Managing General Partner and the Company shall have the right and remedy to have the provisions specifically enforced by any court having jurisdiction, it being acknowledged and agreed by Executive that the services being rendered hereunder to the Managing General Partner and the Company are of a special, unique and extraordinary character and that any such breach or threatened breach may cause irreparable injury to the Partnership and its Subsidiaries and that money damages may not provide an adequate remedy to the Managing General Partner or the Company. Such right and remedy shall be in addition to, and not in lieu of, any other rights and remedies available to the Managing General Partner or the Company at law or in equity in connection with any such breach. Accordingly, Executive consents to the issuance of an injunction, whether preliminary or permanent, consistent with the terms of this Agreement.

(g) Blue Pencil. If, at any time, the provisions of this Section 7 shall be determined to be invalid or unenforceable under any applicable law, by reason of being vague or unreasonable as to area, duration or scope of activity, this Agreement shall be considered divisible and shall become and be immediately amended to only such area, duration and scope of activity as shall be determined to be reasonable and enforceable by the court or other body having jurisdiction over the matter, and Executive and the Managing General Partner agree that this Agreement as so amended shall be valid and binding as though any invalid or unenforceable provision had not been included herein.

(h) EXECUTIVE ACKNOWLEDGES THAT HE HAS CAREFULLY READ THIS SECTION 7 AND HAS HAD THE OPPORTUNITY TO REVIEW ITS PROVISIONS WITH ANY ADVISORS AS HE CONSIDERED NECESSARY AND THAT EXECUTIVE UNDERSTANDS THIS AGREEMENT’S CONTENTS AND SIGNIFIES SUCH UNDERSTANDING AND AGREEMENT BY SIGNING BELOW.

8. Resolution of Differences Over Breaches of Agreement. The parties shall use their good faith efforts to resolve any controversy or claim arising out of, or relating to, this Agreement or the breach thereof, first in accordance with the Managing General Partner’s

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internal review procedures, including prior to any determination of Cause or Good Reason, except that this requirement shall not apply to any claim or dispute under or relating to Section 7 of this Agreement.

9. Successors; Binding Agreement. The rights and benefits of Executive hereunder shall not be assignable, whether by voluntary or involuntary assignment or transfer by Executive, except that payments and benefits payable to Executive hereunder shall inure to the benefit of his estate, spouse and beneficiaries, as applicable. This Agreement shall be binding upon, and inure to the benefit of, the successors and assigns of the Managing General Partner, and the estate, heirs, executors, administrators, beneficiaries and permitted assigns of the Executive, and shall be assignable in whole (but not in part) by the Managing General Partner to any entity acquiring, directly or indirectly, the Company or substantially all of the assets of the Company, whether by merger, consolidation, sale of assets or similar transactions, without, however, relieving the Managing General Partner of its obligations hereunder (including those after the date of assignment).

10. Notice. For the purposes of this Agreement, notices, demands and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given on the date personally delivered or three business days following the date deposited in the United States mail (certified or registered, return receipt requested, postage prepaid), addressed, in case of Executive, to the last address on file with the Company and, if to the Managing General Partner, to its executive offices or to such other address as any party may have furnished to the other in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt.

11. Delay in Payment. Notwithstanding the timing requirements set forth above, in the event that the Executive is a “specified employee” at the time of his “separation from service” according to the meaning of such terms in Treasury Regulation § 1.409A-1(i), any payment due to Executive pursuant to this Agreement that is required to be delayed for a six month period in accordance with the restrictions of section 409A of the Code and the regulations promulgated thereto, shall be paid instead to the Executive on the first day of the seventh month following the Executive’s Date of Termination.

12. Governing Law; Venue; Severability. This Agreement is governed by, and is to be construed and enforced in accordance with, the laws of the State of Texas without regard to principles of conflicts of laws. Each party (i) consents to submit itself and himself to the personal jurisdiction of any federal or state court located in Houston, Texas if any dispute arises out of this Agreement or any of the transactions contemplated herein, (ii) agrees that it or he will not attempt to deny or defeat such personal jurisdiction by motion or other request for leave from any such court and (iii) agrees that it or he will not bring any action relating to this Agreement or any of the transactions contemplated herein in any court other than any federal or state court sitting in Houston, Texas. Except as otherwise provided herein, if any portion of this Agreement is at any time deemed to be in conflict with any applicable statute, rule, regulation or ordinance, such portion shall be deemed to be modified or altered to conform thereto or, if that is not possible, to be omitted from this Agreement, and the invalidity of any such portion shall not affect the force, effect and validity of the remaining portion hereof.

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13. Amendment. No provisions of this Agreement may be amended, modified, or waived unless such amendment or modification is agreed to in writing signed by Executive and by a duly authorized officer of the Managing General Partner, and such waiver is set forth in writing and signed by the party to be charged. No waiver by either party hereto at any time of any breach by the other party hereto of any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

14. Survival. The respective obligations of, and benefits afforded to, Executive and Managing General Partner and the Company as provided in Section 7 of this Agreement shall survive the termination of this Agreement, together with any other provisions hereof which by their nature contemplate survival.

15. Mutual Non-Disparagement Obligation. Executive agrees that he shall not, during the employment relationship and for a period of three years after the Date of Termination, make any disparaging remarks concerning the Company, the Managing General Partner, the Partnership or any of its Subsidiaries. The Managing General Partner agrees that it shall not, and it shall not cause or permit the Company, the Partnership or any of the Partnership’s other Subsidiaries to, during the employment relationship and for a period of three years after the Date of Termination, make any disparaging remarks concerning the Executive.

16. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

17. Entire Agreement. This Agreement sets forth the entire agreement of the parties hereto in respect of the subject matter contained herein and supersedes all prior agreements, promises, covenants, arrangements, communications, representations or warranties, whether oral or written, in respect of such subject matter. Any prior agreement of the parties hereto in respect of the subject matter contained herein is hereby terminated and canceled as of the date hereof.

18. Section Headings. The section headings in this Agreement are for convenience of reference only, and they form no part of this Agreement and shall not affect its interpretation.

19. Withholding. All payments hereunder shall be subject to any required withholding of Federal, state and local taxes pursuant to any applicable law or regulation.

20. Representation. Executive represents and warrants to the Managing General Partner, and Executive acknowledges that the Managing General Partner has relied on such representations and warranties in employing Executive to serve as the President and Chief Executive Officer of the Company, that neither Executive’s duties as an employee of the Managing General Partner nor his performance of this Agreement will breach any other agreement to which Executive is a party, including, without limitation, any agreement limiting the use or disclosure of any information acquired by Executive prior to his employment by the Managing General Partner. In addition, Executive represents and warrants and acknowledges that the Managing General Partner has relied on such representations and warranties in employing Executive, and that he has not entered into, and will not enter into, any agreement, either oral or written, in conflict herewith.

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21. Mitigation. Executive shall not be required to mitigate amounts payable under this Agreement by seeking other employment or otherwise, and there shall be no offset against amounts due Executive under this Agreement on account of subsequent employment except as specifically provided herein.

[Signature page follows]

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the date first above written.

REGENCY GP, LLC
By:	/s/ Byron R. Kelley
Name:	Byron R. Kelley
Title:	President
EXECUTIVE
/s/ Randall H. Dean
Randall Dean

Signature page to Employment Agreement

EX-10.21

Exhibit 10.21

MASTER LEASE AGREEMENT

This MASTER LEASE AGREEMENT (this “Master Lease”), dated as of February 26, 2009, is between Caterpillar Financial Services Corporation (“Lessor”), a Delaware corporation whose address is 2120 West End Avenue, Nashville, Tennessee 37203, and CDM Resource Management LLC (“Lessee”), a Texas limited liability company with a principal address of 20405 Tomball Pkwy, Suite 310, Houston, TX, 77070.

In consideration of the mutual covenants and agreements hereinafter set forth, the parties hereto agree as follows:

Section 1. Definitions. The capitalized terms used in this Master Lease and not otherwise defined herein shall have the respective meanings specified in Appendix A hereto, unless the context hereof shall otherwise require.

Section 2. Master Lease. Lessor hereby leases to Lessee and Lessee hereby leases from Lessor the Equipment and other property described on each Lease Schedule executed from time to time by Lessor and Lessee in a form acceptable to Lessor (each a “Schedule”). Each Schedule shall expressly incorporate the terms of this Master Lease and shall constitute a separate lease along with any other writing expressly incorporated into the Master Lease or the Schedule. The terms “Lease” or “this Lease” as used herein shall refer to each and every Schedule that incorporates this Master Lease and any other writing expressly incorporated into the Master Lease or such Schedule. In the event of any conflict between the Master Lease and any Schedule, the terms of the Schedule shall control. Upon Lessee’s satisfaction of all conditions precedent to effectiveness of this Master Lease, including those set forth in Section 9 with respect to the execution of Schedules: (a) this Master Lease shall constitute a legal commitment by Lessor to lease equipment in accordance with the terms herein and in each such Schedule and (b) Lessor shall be obligated to enter into Schedules and purchase and lease the equipment or other property pursuant thereto. After executing a Schedule, Lessor shall have no obligation to purchase or finance any Equipment until the satisfaction of all conditions precedent to Lessor’s purchase of Equipment pursuant to the terms of the Master Lease and said Schedule.

Section 3. Title; UCC 2A Finance Lease; Waivers.

(a) Lessee and Lessor intend that: (i) each Lease constitutes a true “lease” that is a “finance lease” as such terms are defined in Article 2A of the UCC and does not create a “security interest” as defined in the UCC; (ii) Lessor is and shall remain the owner of the Equipment (unless sold by Lessor pursuant to any Lease Document); (iii) Lessee shall not acquire any right, title, equity or interest in or to such Equipment other than the right to possess and use the Equipment in accordance with Lessee’s leasehold interest under the Lease. If, notwithstanding the intention of the parties and the economic realities of this Lease, this Lease is deemed to create a security interest, Lessee shall be deemed to have granted to Lessor as security for Lessee’s obligations hereunder, a first priority security interest in the Equipment and all proceeds thereof. Until Lessee’s obligations under each Schedule are satisfied in full, if requested by Lessor or if required by Applicable Law, Lessee shall at Lessee’s sole cost and expense permanently affix and maintain on any or all Equipment or as many items as required, as determined by Lessor or as required by Applicable Law, a sign, legend, plate, plaque, tag or other identifying label in a prominent place that discloses Lessor’s ownership or that such Equipment is leased from Lessor under such Schedule.

(b) Lessee further acknowledges that at least one of the following is true: (i) Lessee has selected the Supplier (as defined in Article 2A of the UCC), has directed Lessor to purchase the Equipment from the Supplier and has been informed by Lessor in writing (and is so hereby informed) that (A) Lessee is entitled under Article 2A of the UCC to certain rights under the Supply Contract (as defined in Article 2A of the UCC), and (B) Lessee may contact the Supplier to receive an accurate and complete

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statement from the Supplier of any such rights and any disclaimers and limitations of them or of remedies; or (ii) Lessee has received, reviewed and approved a copy of the Supply Contract covering the Equipment purchased from the Supplier thereof for lease to Lessee. To the fullest extent permitted by Applicable Law, Lessee hereby waives any and all rights and remedies conferred upon lessees by Sections 2A-508 through 2A-522 of the UCC as currently in force on the date hereof or otherwise conferred upon Lessee by the UCC. Lessee further waives, to the extent permitted by Applicable Law notice of sale or other disposition of the Equipment.

Section 4. Term, Rent Termination and Purchase Option

4.1 Lease Obligation; Term. The Term of each Schedule (the “Term”) will consist of: (a) the Initial Term set forth on the Schedule, if any; (b) the Base Term and (c) the Renewal Term. The “Initial Term” (if any) shall commence on the date set forth on the Schedule and end on the Base Term Commencement Date. The “Base Term” shall commence on the Base Term Commencement Date and, unless terminated or extended as provided herein, shall end on the same day of the month as the Base Term Commencement Date at the end of One Hundred Twenty (120) months. Any Renewal Term will be as set forth in Section 5.3 hereof.

4.2 Rent; Late Payments. Lessee hereby covenants, agrees, and promises to pay to Lessor quarterly Rent, in arrears, plus applicable Taxes as increased from time to time in the amounts and pursuant to the terms and conditions of the applicable Schedule. Unless otherwise directed by Lessor, Rent and other amounts payable hereunder shall be paid to Lessor in the manner set forth in the applicable Schedule or in such other manner as Lessor shall specify in writing from time to time. All amounts payable to Lessor hereunder for which a payment date is expressly set forth herein (including Rent) shall be payable without notice or written demand by Lessor. All amounts payable to Lessor hereunder for which no payment date is expressly set forth herein shall be payable on written demand by Lessor to Lessee. Payments which are due on a day which is not a Business Day shall be payable on the next succeeding Business Day. If any Rent payment or any other Obligation under this Lease is not received by Lessor when due, Lessee shall pay to Lessor, in addition to such Rent or other payment, late fees on such amounts from the date due until payment is received by Lessor equal to the lesser of (a) five percent (5%) per annum on such amount (it being understood and agreed by the parties that such percentage shall be applied based on a calendar year of 365 days, with the interest on any given day being 1/365 of the total interest for the calendar year); and (b) the highest charge allowed by Applicable Law. The Lessee shall pay the reasonable expenses of Lessor (including fees and out-of-pocket expenses of Lessor’s attorneys and Lessor’s engineer) incurred at the request of Lessee, or in the performance of its duties under any of the Lease Documents, or in connection with any litigation which may at any time be instituted involving the Equipment or the Lease Documents, or in the pursuit of any remedies under the Lease Documents.

4.3 Termination. Each Lease shall terminate upon the earlier of (a) the end of the Term; or (b) the date upon which Lessor or Lessee terminates the Lease pursuant to any terms hereunder. No termination (whether by default or the passage of time) shall affect or impair the rights, powers or privileges of Lessor or the liabilities of Lessee relating to (i) any transaction or event occurring prior to the effective date of such termination or (ii) any of the undertakings, agreements, covenants, indemnifications, representations or warranties of Lessee contained in the Lease Documents. All such undertakings, agreements, covenants, indemnities, representations, and warranties of Lessee shall survive such termination and Lessor shall retain all of its rights and remedies under the Lease Documents.

4.4 Noncancellable; Absolute and Unconditional. Lessee agrees that each Schedule shall be NON-CANCELABLE and that Lessee’s obligation to pay any and all amounts due under the terms of each such Schedule promptly when due is ABSOLUTE AND UNCONDITIONAL, shall not be subject to cancellation, termination, modification or repudiation by Lessee, and shall be paid and performed by

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Lessee without notice or demand and without any abatement, reduction, diminution, setoff, defense, counterclaim or recoupment whatsoever, including: (i) any past, present or future claims that Lessee may have against Lessor, Vendor, any Permitted User or performance of any services relating to, any Equipment or any other part of the Equipment, or any other Person whatsoever; (ii) any defect in the title, condition, design, or operation of, or lack of fitness for use of, or any damage to, or loss of, all or any part of the Equipment or part of the Equipment from any cause; (iii) the existence of any Liens on the Equipment or any other part of the Equipment; (iv) the invalidity, unenforceability or disaffirmance of this Lease or any other Lease Document; (v) the prohibition of or interference with the use or possession by Lessee of all or any part of the Equipment or any other part of the Equipment, for any reason whatsoever, including by reason of: (A) claims for patent, trademark or copyright infringement; (B) present or future governmental laws, rules or orders; (C) the insolvency, bankruptcy or reorganization of any Person; and (D) any other cause whether similar or dissimilar to the above, any present or future law to the contrary notwithstanding (each, an “Abatement”). In no event will Lessee’s obligations under this Lease be excused or suspended by reason of strikes, embargoes, riot, war, acts of hostility, storm, fire, earthquake, acts of God or any other cause or event including frustration of purpose, impracticability or impossibility. Lessee may not cancel this Lease, and unless expressly provided otherwise herein or in the applicable Schedule, Lessee may not make any full or partial prepayments with respect to sums due hereunder.

Section 5. Lessee Options

5.1 Early Buyout Option. Lessor hereby grants to Lessee the option, exercisable only as provided herein, to purchase all but not less than all Equipment leased pursuant to each Schedule prior to the expiration of the Term for such Schedule, subject to the following: (a) so long as no Event of Default, or event which with notice, lapse of time or both would become an Event of Default shall have occurred, Lessee shall have the right at its option to purchase all, but not less than all, Equipment leased pursuant to each Schedule (the “EBO Equipment”) on the Fifth (5th) and Seventh (7th) anniversaries of the Base Term Commencement Date (each an “EBO Date”); provided, however, that Lessee shall have given at least ninety (90) days but not more than one hundred fifty (150) days prior written notice (which notice shall be irrevocable without Lessor’s written consent) to Lessor; (b) on the EBO Date: (i) Lessee shall pay to Lessor an amount equal to: (A) Seventy-Five Percent (75%) of the Lessor’s Cost set forth on the Schedule in the event the EBO Date is the Fifth anniversary of the Base Term Commencement Date or Fifty-Six Percent (56%) of the Lessor’s Cost set forth on the Schedule in the event the EBO Date is the Seventh anniversary of the Base Term Commencement Date; plus (B) all other amounts due under such Schedule with respect to the EBO Equipment, including the Rent payment due on the EBO Date and applicable Taxes and other amounts due or payable with respect to such sale and (ii) Lessor shall sell such Equipment for cash to Lessee, AS IS, WHERE IS, without recourse or warranty (except that Lessor has whatever title (if any) to the Equipment that was conveyed to it by the Vendor free of any security interest arising solely by reason of a claim against Lessor that Lessee is not responsible to remove pursuant to this Lease). Provided that Lessee has complied with all obligations contained herein, such Schedule shall be deemed terminated on the EBO Date and Lessee shall have no further obligations to pay Rent thereunder. Notwithstanding anything to the contrary herein, Lessee hereby agrees that: (1) Lessee’s exercise of the Early Buyout Option under this Section 5.1 with respect to Equipment leased pursuant to one Schedule shall be automatically deemed to be an election of its Early Buyout Option to purchase all Equipment leased under all other Schedules to this Master Lease at the same EBO Date (Fifth or Seventh anniversary, as applicable) for such other Schedules in accordance with the terms thereof (which notice shall be irrevocable without Lessor’s written consent); and (2) if Lessee elects not to exercise its Early Buyout Option to purchase Equipment pursuant to this Section 5.1 on any EBO date with respect to any Schedule, it shall be deemed to have waived its rights to exercise its Early Buyout Option to purchase all Equipment leased under all other Schedules to this Master Lease on the same EBO Date.

5.2 Purchase Option. Provided that no Event of Default, and no event which with lapse of time or giving of notice or both would become an Event of Default, has occurred, Lessee may elect, by

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giving Lessor not less than one hundred eighty (180) days but not more than two hundred forty (240) days prior written notice (which notice shall be irrevocable without Lessor’s written consent), to purchase all, but not less than all, Equipment (the “Purchased Equipment”) as of the last day of the Base Term. In the event Lessee elects to purchase the Purchased Equipment from Lessor, it shall pay to Lessor on the date of expiration of the Base Term an amount equal to Twenty Four and Fifteen One-Hundredths Percent (24.15%) of the Lessor’s Cost set forth on the Schedule together with all other amounts due under such Schedule with respect to the Purchased Equipment plus applicable Taxes and other amounts due or payable with respect to such sale. All Purchased Equipment shall be sold to Lessee on an AS IS, WHERE IS BASIS, without recourse or warranty (except that Lessor has whatever title (if any) to the Equipment that was conveyed to it by the Vendor free of any security interest arising solely by reason of a claim against Lessor that Lessee is not responsible to remove pursuant to this Lease). Lessor and Lessee agree that the percentage multiplied by Lessor’s Cost in this Section 5.2 is a reasonable estimate of the fair market value of the Equipment at the end of the Base Term. Notwithstanding anything to the contrary herein, Lessee hereby agrees that: (a) Lessee’s exercise of its Purchase Option with respect to Equipment leased pursuant to one Schedule shall be automatically deemed to be an election of its option to purchase all Equipment leased under all other Schedules to this Master Lease at the end of the Base Term of such Schedules in accordance with the terms thereof (which notice shall be irrevocable without Lessor’s written consent); and (b) if Lessee elects not to exercise its Purchase Option right with respect to any Schedule, it shall be deemed to have waived its rights to exercise its option to purchase all Equipment leased under all other Schedules to this Master Lease.

5.3 Renewal Option.

(a) Provided that no Event of Default, and no event which with lapse of time or giving of notice or both would become an Event of Default has occurred, Lessee shall have the option, exercisable upon not less than one hundred eighty (180) days but not more than two hundred forty (240) days prior written notice (which notice shall be irrevocable without Lessor’s written consent), to extend the Base Term for an additional period of Sixty (60) months (the “Renewal Term”). During the Renewal Term, all of the terms and provisions of this Lease, shall continue to apply provided, however that quarterly Rent shall be adjusted at the beginning of the Renewal Term to equal the Fair Market Rental Value at such time. As used herein, the term “Fair Market Rental Value” means the rental value of the Equipment as determined on the basis of, and will be equal in amount to, the value which one would obtain in an arm’s-length transaction between an informed and willing lessee-user (other than a lessee currently in possession and a used equipment dealer) and an informed and willing lessor under no compulsion to lease and, in such determination it will be assumed that the Equipment is in the condition required to be maintained and returned under this Lease and is value on an installed basis and the costs of removal from current location shall not be a deduction from such valuation. For purposes of this Master Lease, the Fair Market Rental Value for the Equipment shall be determined by mutual agreement of Lessor and Lessee. If such mutual agreement cannot be reached, then it shall be determined by the Appraisal Process. If Fair Market Rental Value is not determined by the end of the Base Term, the Base Term shall, at Lessor’s election, be extended at the current Rental amount until Fair Market Rental Value is calculated as provided herein. At the end of the Renewal Term, Lessee shall comply with the provisions of this Lease regarding return or purchase of the Equipment.

(b) Notwithstanding anything to the contrary herein, Lessee hereby agrees that: (i) Lessee’s exercise of its Renewal Option with respect to Equipment leased pursuant to one Schedule shall be automatically deemed to be an election of its Renewal Option with respect to all Equipment leased under all other Schedules to this Master Lease at the end of the Base Term of such Schedules in accordance with the terms thereof (which notice shall be irrevocable without Lessor’s written consent); and (ii) if Lessee elects not to exercise its Renewal Option with respect to any Schedule, it shall be deemed to have waived its rights to exercise its Renewal Option with respect to all Equipment leased under all other Schedules to this Master Lease.

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5.4 Return of Equipment

(a) Unless Lessee purchases the Equipment, if allowed in accordance with the terms hereof: (i) Lessee shall be obligated to return the Equipment to Lessor at the end of the Term or as required by Lessor upon the occurrence of an Event of Default under Section 15.2; and (ii) Lessee shall at its sole expense demobilize, load, and transport the Equipment to any location in the Continental United States designated by Lessor such that possession is delivered to Lessor on the last day of the Term or immediately upon the occurrence of an Event of Default; provided, however, that if the location specified by Lessor is outside of the Return Radius from the Property where the Equipment was located pursuant to the applicable Permitted Use Agreement (the “Site Location”), Lessor shall pay that portion of the actual transportation costs which exceeds the transportation costs which would have been incurred by Lessee in transporting the Equipment a distance equal to the maximum Return Radius. As used herein the “Return Radius” shall mean the number of miles from the Vendor’s location from which the Equipment was originally delivered to the Site Location.

(b) Any and all components of the Equipment returned to Lessor shall be in the same physical and mechanical condition as originally delivered (except for Reasonable Wear and Tear) and in Average Saleable Condition. For purposes of this Lease “Reasonable Wear and Tear” shall mean: (i) the results of normal use of the Equipment as originally intended assuming use and maintenance in accordance with the Vendor’s recommendations and the complete absence of any casualty, misuse, abuse, abandonment, improper care, accident, negligence or similar occurrence with respect to the Equipment, whether or not the Equipment is in use at the time of said occurrence; and (ii) use that does not, in any way, impair the function of the Equipment or prevent the Equipment from promptly being placed into use. For purposes of this Lease “Average Saleable Condition” shall mean such condition that: (A) all components have at least a fifty (50%) remaining life until the next scheduled overhaul; (B) the Equipment has been properly operated and maintained in accordance with prudent industry practice; (C) the Equipment operates at its rated horsepower, temperature, pressure, fuel consumption, capacity, and efficiency and energy requirement, Reasonable Wear and Tear excepted; and (D) in accordance with any additional return requirements set forth in the applicable Schedule.

(c) If Lessee is required to return the Equipment in accordance with the terms hereof, Lessee shall provide Lessor, at Lessee’s sole cost and expense at least ninety (90) days prior to the end of the Term (or immediately if the Equipment is returned due to an Event of Default), with a true, accurate and complete set of all material documentation for the Equipment setting forth a detailed description of its components and its operating and maintenance history, all in form reasonably satisfactory to Lessor. Lessee shall also, at its sole expense (but not to exceed $250.00 per compressor package) at least sixty (60) days prior to the end of the Base Term (or the Renewal Term if Lessee has exercised its Renewal Option) have an authorized manufacturers’ representative, or other person approved in advance in writing by Lessor, review each compressor package’s operating and maintenance history and, if requested by Lessor, conduct various field tests to confirm that natural gas compressor packages constituting the Equipment is in Average Saleable Condition. Lessor shall also have the right to make such inspections and tests as it deems necessary or desirable to determine if the Equipment is in conformance with the requirements listed in this Section 5.4.

(d) Lessor shall indicate its approval or rejection of the condition of the returned Equipment by having its authorized representative sign and deliver to Lessee the Form Acceptance upon Return. If the Equipment does not meet the physical and/or mechanical requirements set forth above, then Lessee is to make the necessary corrections specified on the Form Acceptance upon Return within thirty (30) days (during which time Rent shall accrue and become due). Once such corrections are satisfactorily made by Lessee as evidenced solely by Lessor’s execution of the acceptance portion of the Form Acceptance upon Return, the subject Equipment will be deemed accepted by Lessor for purposes of in this Section 5.4. If the Equipment is not in the condition required, Lessee shall pay to Lessor, on demand, all costs, and

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expenses incurred by Lessor to bring the Equipment into the required condition. Lessee expressly agrees that, in the event Lessee does not elect to purchase the Equipment in accordance with the terms hereof, Lessor has the right to arrange for the sale or other disposition prior to the Equipment’s return (provided that such sale shall not close until the end of the applicable Term) and Lessee agrees to facilitate any such sale or disposition of the Equipment and that Lessor, its agents or employees, shall have the right to enter the Property for the purpose of showcasing the Equipment for sale or other disposition.

(e) Any entrance on the Property for inspection, showcasing or other purposes under this Section 5.4 shall be conducted in accordance with the provisions of Section 7.3(b) hereof.

Section 6. Warranty Disclaimer; Selection; Additional Disclaimers and Waivers

6.1 Warranty Disclaimer; No Representations. LESSOR DOES NOT MAKE ANY, AND HEREBY DISCLAIMS, EACH AND EVERY, WARRANTY OR REPRESENTATION, EITHER EXPRESS OR IMPLIED, AS TO: (A) THE MERCHANTABILITY OR FITNESS OF THE EQUIPMENT OR ANY OTHER PART OF THE EQUIPMENT FOR ANY PARTICULAR PURPOSE; (B) THE QUALITY, THE CAPACITY OF THE EQUIPMENT OR THE WORKMANSHIP OF THE EQUIPMENT OR THE ABILITY OF THE EQUIPMENT, OR ANY PORTION THEREOF TO SATISFY THE REQUIREMENTS OF ANY LAW, RULE, SPECIFICATIONS OR CONTRACT THAT MAY BE APPLICABLE THERETO OR AS TO TITLE TO THE EQUIPMENT OR ANY COMPONENT OR ITEM THEREOF; AND (C) THE LEGAL, TAX OR ACCOUNTING TREATMENT OF THE TRANSACTIONS CONTEMPLATED HEREBY. IT IS AGREED THAT ALL SUCH RISKS, AS BETWEEN LESSOR, ON THE ONE HAND, AND LESSEE, ON THE OTHER HAND, ARE TO BE BORNE BY LESSEE AT ITS SOLE RISK AND EXPENSE.

6.2 Selection; Additional Waivers; Purchase Agreements.

(a) Lessor shall have no responsibility or liability to Lessee or any other Person with respect to any of the following, regardless of any active or passive negligence of Lessor: (i) any liability, loss or damage caused or alleged to be caused directly or indirectly by any part of the Equipment or by any inadequacy thereof or caused or alleged to be caused directly or indirectly by any part of the Equipment or by any inadequacy thereof or deficiency or defect therein or by any other circumstance in connection therewith; (ii) the transportation, ownership, possession, use, construction, operation, performance, maintenance, storage, repair, reconstruction or return of any part of the Equipment or any risks relating thereto; (iii) any interruption of service, loss of business or anticipated profits or consequential damages. Lessee further acknowledges and agrees that (A) it has selected the Equipment and each and every part thereof and has not relied on any representation or warranty by Lessor in connection with such selection; (B) Lessor is not the manufacturer of the Equipment or any component of the Equipment; (C) the Equipment and all other components of the Equipment are, and will be upon execution by Lessee of the applicable Schedule, of a size, design and make selected by Lessee, suitable for Lessee’s purposes, containing all safety features deemed necessary by Lessee, (D) Lessor is not an agent of Vendor or supplier of any part of the Equipment or any services in connection therewith or any party representing or acting on behalf of any of the foregoing and no such parties are agents of Lessor or otherwise authorized to bind Lessor to any representation, warranty or agreement; and (E) Lessor disclaims, and Lessee hereby waives, any right to seek or recover from Lessor any punitive, consequential or incidental damages which might be alleged to arise from a breach of this Lease, any assignment of this Lease, the delivery or use of the Equipment or any other claim which might be made by Lessee or its assigns against Lessor.

(b) Lessee agrees that: (i) each Purchase Agreement shall identify Lessor as the Person with the right to purchase the Equipment pursuant to the applicable Purchase Agreement, the right to take title to such Equipment and the right to be named as the purchaser in the bill of sale for such Equipment; and (ii) each Purchase Agreement, or the bill of sale for such Equipment to be issued to Lessor in accordance with

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the terms thereof, shall afford Lessor the benefits of all warranty and indemnity provisions contained in any such Purchase Agreement. Notwithstanding anything to the contrary contained herein, Lessor shall have no liability under any Purchase Agreement, shall not be obligated to perform any of the obligations or duties of Lessee under any Purchase Agreement and shall not be obligated to make any payment thereunder for the benefit of Lessee (other than under the terms and conditions set forth in this Lease). Each Purchase Agreement shall be acceptable to Lessor and Lessee will have no right to bind Lessor to any change in the Purchase Agreement, any delivery schedule, or any other agreement whatsoever and Lessee not shall not change any Purchase Agreement without Lessor’s prior written consent. So long as Lessee is not in default hereunder, Lessor hereby appoints and constitutes Lessee as its agent and attorney-in-fact during the term of this Lease to assert and enforce from time to time, for the account of Lessor, at Lessee’s sole cost and expense, whatever claims and rights Lessor may have against any Vendor for breach of warranty.

Section 7. Possession, Maintenance and Use

7.1 Maintenance and Use of Equipment. Lessee, at its expense, shall maintain the Equipment in good operating order, repair and condition and shall perform maintenance on the Equipment and other components of the Equipment at least as frequently as set forth in any applicable operator’s guide, service manual and/or lubrication and maintenance guide for the Equipment. Lessee covenants and agrees that: (a) it shall use, operate, maintain or store the Equipment properly, carefully, safely or in accordance with: (i) all Applicable Laws or regulations of any Governmental Authority; (ii) all instructions, warranty provisions, operating manuals prepared or released by the Vendor and any manufacturer, supplier or maintenance organization for the Equipment, including any service agreement; (iii) all requirements of insurance maintained hereunder; and (iv) all Permits and Related Rights; and (b) it will not: (i) permit the Equipment to be used for any purpose other than in the conduct of its business; (ii) abandon the Equipment; (iii) permit the use of the Equipment to be changed from that specified herein; (iv) permit any Equipment to be removed from the location set forth on the Schedule as the location of the Equipment without the prior written consent of Lessor; (v) create, incur or allow to exist any Lien on any of its rights hereunder or to the Equipment except for Liens granted to Lessor pursuant to the Lease Documents; or (vi) permit the Equipment to be operated Persons other than Persons who are well-trained, competent and have sufficient experience and training to operate the Equipment satisfactorily and correctly; (c) the ordinary maintenance and repairs performed by Lessee pursuant to any provisions of this Lease will not change the purpose or character of the Equipment or materially enhance its value (as opposed to preserving its value or slowing its depreciation); (d) at the end of the Term, the Equipment can be removed from the location in which it will be used by Lessee and the use of the Equipment by a Person other than Lessee or an affiliate of Lessee will be commercially feasible, assuming normal market conditions; (e) the Rent does not materially exceed the Fair Market Rental Value of the Equipment; (f) to the best of Lessee’s knowledge, pursuant to general business practices, it is not unusual or extraordinary for property the same as, or similar to, the Equipment to be the subject of a lease for use similar to the use intended by Lessee; (g) Lessee shall keep accurate records of (i) all inventory and supplies used in connection with the operation of the Equipment or stored at the Equipment (including any solvents, lubricants or Hazardous Materials), (ii) the operations of the Equipment, and (iii) the occurrence of any event that may reasonably be considered to violate a Environmental Law or result in Environmental Loss, and provide copies of such written records to Lessor within five (5) days of Lessor’s written request; and (h) Lessee (or a designee approved by Lessor) shall be the sole operator of the Equipment and Lessor shall not have any obligation or responsibility to operate the Equipment or with respect to any designee approved by Lessor.

7.2. Alterations to Equipment. Provided that no Event of Default exists under this Lease and no event which with lapse of time or giving of notice or both would become an Event of Default, Lessee may at its sole cost and expense make any alterations, additions, repairs, modifications or attachments (“Improvements”) to the Equipment or any other part of the Equipment provided that Lessee notifies

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Lessor in advance of such action in writing (except in those cases where Lessee must make emergency or other immediate Improvements to preserve or return the Equipment to operational status or comply with Applicable Law, in which case advance notice shall not be required and Lessee shall notify Lessor as soon as is practicable after making such Improvements) and provided further that such Improvements, in Lessor’s judgment: (a) do not reduce the value or general usefulness of any part of the Equipment; (b) do not impair the certification, performance, safety, quality, capability, use or character of any part of the Equipment, or alter the purpose for which such Equipment was leased under this Lease; (c) do not expose Lessor or any part of the Equipment to any Lien; (d) do not adversely affect insurance coverage benefiting Lessor; (e) are of a kind that customarily are made by lessees or purchasers of Equipments similar to the Equipment; and (f) will not cause the Equipment to become limited use property within the meaning of Revenue Procedure 76-30 or materially reduce its general usefulness. If no Event of Default has occurred and is continuing and such Improvements are readily removable without causing material damage to the Equipment, Lessee shall have the right to remove any Improvements at its own expense prior to the return of the Equipment to Lessor, provided that removal will not impair its originally intended function or use. If any Improvements are not readily removable without causing material damage to the Equipment (or if removable but not removed by Lessee as when returned to Lessor), such Improvement shall automatically and without payment by Lessor become the property of Lessor subject to all provisions of this Lease.

7.3 Inspection.

(a) Lessor and its agents shall have the right at Lessee’s sole expense to inspect the Equipment, observe its use and inspect any information, written or otherwise, relating to it and to perform due diligence examinations and audit Lessee not to exceed four times in any calendar year; provided that Lessor is not obligated to do so and provided, further, that no restrictions on how frequently Lessor may conduct such inspections shall be applicable if a default or Event of Default shall have occurred and then be continuing. Lessor assumes no responsibility and waives no rights as a result of any inspection or observation or the lack thereof.

(b) So long as no default or Event of Default shall have occurred and then be continuing: (i) Lessor shall provide Lessee with reasonable advance notice of such inspections; (ii) such inspections shall occur only at reasonable times during usual business hours; and (iii) Lessee shall have the right to have its representatives present during any such inspections or other entry on the Property by Lessor, and Lessor shall not enter the Property without having a Lessee representative present.

7.4 Personal Property. The Equipment shall remain personal property regardless of its use or manner of attachment to the Property. The Lessee recognizes that the Equipment and any improvements represented thereby are removable and separable from, and not essential to, the Property and recognizes the right of Lessor to remove any portion of the Equipment and each Permitted Use Agreement shall contain similar statements from the applicable Permitted Users in form and substance satisfactory to Lessor.

Section 8. Representations, Warranties and Covenants.

8.1 Representations and Warranties. In order to induce Lessor to enter into this Lease, Lessee represents and warrants the following to Lessor as of the date of this Master Lease and as of the date of each and every Schedule entered into pursuant hereto unless otherwise stated herein:

(a) Lessee is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly licensed or qualified to transact business in all other jurisdictions where the character of the property owned or leased or the nature of the business transacted by it makes such licensing or qualification necessary.

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(b) To the Best of Lessee’s Knowledge, Parent is a master limited partnership duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly licensed or qualified to transact business in all other jurisdictions where the character of the property owned or leased or the nature of the business transacted by it makes such licensing or qualification necessary. As used herein in this Section 8, “To the Best of Lessee’s Knowledge” shall mean that no President or Vice President is aware of any facts that would give such Person actual knowledge or actual notice, and that no such Person has any current actual knowledge or current actual notice, that any such representations or warranties are false. For the avoidance of doubt the term “To the Best of Lessee’s Knowledge” shall not include or in any way required any inquiry or other investigation on the part of Lessee or any of its officers, employees, agents or other representatives.

(c) Lessee has all requisite power and authority, corporate or otherwise, and is duly authorized and empowered to: (i) enter into, execute, deliver and perform all of its Obligations under the Lease Documents; (ii) conduct its business as presently conducted; and (iii) own and operate its property and to operate the Equipment. The execution, delivery and performance by Lessee of this Lease and each of the other Lease Documents and the leasing hereunder have been duly authorized by all necessary action and do not and will not (A) require any consent or approval of additional members of Lessee or any authorization, consent or approval by any Governmental Authority, commission, board, bureau, agency or instrumentality, domestic or foreign, (B) violate any provision of any Applicable Law, rule or regulation or of any order, writ, injunction or decree presently in effect having applicability to Lessee or of the formation or governing documents of either such entity, (C) result in a breach of or constitute a default under any indenture or loan or credit agreement (including any such agreements in effect as of the date hereof between Lessee and any bank) or any other agreement, lease or instrument to which Lessee is a party or by which Lessee or its property may be bound or affected (except for those with Persons who have consented in writing thereto with copies of such consents delivered to Lessor), which breach or default would reasonably be expected to have a material adverse effect as described in Section 15.1(j), or (D) To the Best of Lessee’s Knowledge, result in a breach of or constitute a default under any indenture or loan or credit agreement (including any such agreements in effect as of the date hereof between Parent and any bank) or any other agreement, lease or instrument to which Parent is a party or by which Parent or its property may be bound or affected (except for those with Persons who have consented in writing thereto with copies of such consents delivered to Lessor).

(d) This Lease is, and each of the other Lease Documents to which Lessee is a party, when delivered will be, a legal, valid, and binding obligation of Lessee enforceable against such entity in accordance with their respective terms.

(e) No fact is known to Lessee that has had or can reasonably be expected in the future to have a material adverse effect on the business, property or financial condition of Lessee (or, To the Best of Lessee’s Knowledge, Parent) which has not been previously disclosed to Lessor by Lessee.

(f) As of the date of this Master Lease, the assets of Lessee are not subject to any Lien or the terms of any security agreement other than: (i) any Lien in favor of Lessor pursuant to the Lease Documents; (ii) any inchoate Lien incurred in the ordinary course of business that Lessee intends to remove in due course and (iii) any Liens set forth in that certain Fourth Amended and Restated Credit Agreement, dated as of December 1, 2004, among Regency Gas Services, LP, Parent and other parties set forth therein.

(g) Lessee is not in default in any material respect in the performance, observance or fulfillment of any indenture, loan or credit agreement, or to any lease or other agreement or instrument material to Lessee’s business to which it is a party or otherwise bound including this Lease or any other Lease Documents.

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(h) To the Best of Lessee’s Knowledge, Parent is not in default in any material respect in the performance, observance or fulfillment of any indenture, loan or credit agreement, or to any lease or other agreement or instrument material to Parent’s business to which it is a party or otherwise bound.

8.2 Covenants, Representations and Warranties. In order to induce Lessor to enter into this Lease, Lessee covenants, represents, warrants and agrees as of the date of this Master Lease and for the entire Term of each and every Schedule entered into pursuant hereto:

(a) All Financial Statements heretofore and hereafter furnished to Lessor present fairly in all material respects the financial condition of Lessee on the dates thereof and the results of Lessee’s operations for the periods then ended, and were prepared in accordance with GAAP. There are no liabilities of Lessee, fixed or contingent, which are material and are not reflected in the Financial Statements or the notes thereto, other than liabilities arising in the ordinary course of business since the date of the most recent Financial Statement. The Financial Statements do not contain any untrue statement of a material fact or omit a material fact necessary to make the statements contained herein or therein not misleading. Lessee shall at all times keep its books and records in accordance with GAAP. Lessor shall have access to the segment information for Lessee included in the public filings of the financial information filed by the Parent in accordance with Applicable Laws of the U.S. Securities and Exchange Commission. Lessee shall deliver, within thirty (30) days of issue, to Lessor its un-audited, internally generated, quarterly financial statements which are intended for internal use only.

(b) There has been no change in the business, assets, liabilities, business prospects, property, or condition (financial or otherwise) of Lessee (or, To the Best of Lessee’s Knowledge, Parent) which would have a material adverse effect on the business, property, or financial condition of Lessee since the date of the most recent Financial Statements.

(c) All information supplied to Lessor by Lessee (or on behalf of Lessee at Lessee’s direction) with respect to any assets or other properties of Lessee (whether prior to or subsequent to execution of this Lease), is and shall be true and correct in all material respects.

(d) To the Best of Lessee’s Knowledge, all information supplied to Lessor by Lessee (or on behalf of Lessee at Lessee’s direction) with respect to any assets or other properties of Parent (whether prior to or subsequent to execution of this Lease), is and shall be true and correct in all material respects.

(e) Lessee, in the conduct of all of its business affairs, has complied and will continue to comply in all material respects with the requirements of all Applicable Laws, including all Environmental Laws, the noncompliance with which would have a material adverse effect on the business, property or financial condition of Lessee and the ability of Lessee to perform under the Lease Documents. There have been no citations, notices, or orders of noncompliance (that have not been complied with or withdrawn) issued to Lessee under any Applicable Law which would have a material adverse effect on the business, property, or financial condition of Lessee. Lessee has, and is in good standing with respect to, all governmental consents, approvals, authorizations, permits, certificates, inspections and franchises necessary to continue and to conduct in all material respects such entity’s business as heretofore conducted (or proposed to be conducted) by it and to own or lease and operate in all material respects its properties as now owned or leased by it.

(f) Lessee represents and warrants that none of (i) the ownership, leasing or operation of the Equipment, (ii) the sale or use of electricity, steam or other outputs therefrom or (iii) the consummation of any transaction under this Lease or any of the other Lease Documents will cause Lessee to become subject to regulation under (A) the Public Utility Holding Company Act of 1935, as amended from time to time (“PUHCA”) as a “public-utility company,” a “holding company,” or an “affiliate” or “subsidiary company” of a “holding company” or of a “public utility holding company,” as those terms are used in PUHCA, or (B) the Federal Power Act, other than regulation with respect to which the Federal Energy Regulatory Commission, or any successor agency or commission thereto, may grant a waiver or pre-approval in an order authorizing Lessee to sell power.

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(g) Lessee has satisfied all judgments and Lessee is not in default in any material respect with respect to any judgment, writ, injunction, decree, rule, or regulation of any court, arbitrator, Governmental Authority, commission, board, bureau, agency, or instrumentality, domestic or foreign.

(h) There are no actions, suits, investigations or proceedings (“Litigation”) pending or, to the knowledge of Lessee, threatened against or affecting Lessee or the properties of Lessee before any court or Governmental Authority, commission, board, bureau, agency or instrumentality, domestic or foreign, which, if determined adversely to Lessee, could have a materially adverse effect on the financial condition, properties or operations of Lessee or the ability of Lessee to perform hereunder, under any other the Lease Document. Lessee shall promptly notify Lessor in writing of the occurrence of any such Litigation after execution of the Master Lease.

(i) To the Best of Lessee’s Knowledge, there is no Litigation pending or threatened against or affecting Parent or the properties of Parent before any court or Governmental Authority, commission, board, bureau, agency or instrumentality, domestic or foreign, which, if determined adversely to Parent, could have a material adverse effect on the financial condition, properties or operations of Parent or Lessee or the ability of Lessee to perform hereunder, under any other the Lease Document. Lessee shall promptly notify Lessor in writing of the occurrence of any such Litigation after execution of the Master Lease, but only in the event that Lessee acquires knowledge or notice or becomes aware of any such Litigation with respect to Parent or Parent’s properties and such knowledge, notice or awareness meets the definition of the term “To the Best of Lessee’s Knowledge” 8.1(b) above.

(j) Lessee possesses all material licenses, permits, franchises, patents, copyrights, trademarks and trade names or rights thereto, including all Permits and Related Rights, to conduct its business substantially as now conducted and as presently proposed to be conducted, and Lessee is not in violation of any valid rights of others with respect to any of the foregoing.

(k) Lessee has filed or caused to be filed all tax returns which are required to be filed by it pursuant to all applicable federal, state and local laws, regulations or orders. Lessee has paid, or made provision for the payment of, all Taxes which have or may have become due pursuant to said returns or otherwise or pursuant to any assessment received by Lessee or Parent. The charges, accruals, and reserves in respect of income taxes on the books of Lessee is adequate. Lessee knows of no proposed material Tax assessment against it and no extension of time for the assessment of federal, state or local Taxes of Lessee is in effect or has been required or applied for, except as disclosed in the Financial Statements.

Section 9. Conditions Precedent. Any obligation of Lessor to lease the Equipment described in each Schedule shall be subject to the fulfillment to Lessor’s reasonable satisfaction of all of the following conditions as well as any additional conditions set forth in this Lease or any of the other Lease Documents and such other documents, certifications, or acknowledgments as Lessor shall reasonably request:

9.1 No Default. No Event of Default or event or condition that, with notice, lapse of time or both would become an Event of Default shall have occurred and be continuing;

9.2 Lease Documents. Lessor shall have received, in form and substance satisfactory to Lessor, the following items: (a) a fully executed and completed Schedule to which all exhibits, addenda and other attachments referenced therein are attached, which such Schedule shall contain any additional terms applicable to the Equipment and other portion of the Equipment leased thereunder; (b) evidence of Lessee’s insurance policies in accordance with Section 14 hereof with financially sound and reputable insurers, satisfactory to Lessor in its sole discretion; and (c) such other items as Lessor shall reasonably specify in this Lease or any Lease Documents.

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9.3 Permits and Related Rights. Lessee shall have obtained (and, if requested by Lessor, furnished to Lessor copies of) all Permits and Related Rights;

9.4 Organizational/Governing Documents; Existence and Good Standing. Lessor shall have received copies of the organizational and governing documents of Lessee that are certified by an authorized officer of Lessee, as applicable, as being true and correct copies thereof. Lessor shall have received a certificate of existence and good standing certificate with respect to Lessee, issued as of a recent date by the Secretary of State or other appropriate and authorized official of Lessee’s jurisdictions of organization and, if different, a good standing certificate issued with respect to Lessee as of a recent date by the Secretary of State or other appropriate and authorized official of the jurisdiction where the Equipment shall be located;

9.5 Title; Precautionary Lien Priority; No Liens. Lessor shall have received evidence that: (i) upon paying the purchase price of the Equipment to the Vendor, Lessor shall have good title, free of Liens and a precautionary first priority security interest in such Equipment; and (ii) placement of such Equipment at the location set forth on the Schedule will not cause any Lien in favor of any Person other than Lessor to attach to such Equipment.

9.6 Lessee’s Authorization. Lessee shall have provided in form and substance satisfactory to Lessor: (i) properly certified resolutions of Lessee’s manager, managing member or other governing body duly authorizing the execution and delivery of all Lease Documents to which it is a party; and (ii) such other authorizations and other documents as Lessor in its sole discretion may require;

9.7 Financial Statements. Lessor shall have received all financial statements required under Section 10(a);

9.8 Representations and Warranties. All representations and warranties herein shall be true and correct in all material respects as of such date, or to the extent they relate to an earlier date such representations and warranties shall be true and correct in all material respects as of such earlier date and Lessor shall have received a signed copy of a certificate in a form shown on Exhibit D of an authorized officer of Lessee certifying as to the foregoing;

9.9 No Material Adverse Change. There shall not have occurred any material adverse change in the business, assets, liabilities (actual or contingent), operations or condition (financial or otherwise) of the Lessee or, in the facts and information regarding Lessee as represented to date. The determination of what shall constitute a material adverse change shall be at Lessor’s sole reasonable discretion.

9.10 Payment of Fees and Expenses. Lessee shall have paid to Lessor all fees and expenses specified in this Lease as may then be due and payable;

9.11 Permitted Use Agreement; Access.

(a) Lessor shall have approved the Permitted Use Agreement related to the applicable Equipment and shall have received such documentation as Lessor reasonably requires to assure it of access to the Property for purposes of inspection and enforcement of its rights hereunder upon the occurrence of an Event of Default.

(b) Notwithstanding Section 9.11(a) hereof, Lessor agrees that Lessee may enter into one or more Schedules with respect to Equipment (“Uncommitted Equipment”) that is not subject to a Permitted Use Agreement at the time the Schedule is executed so long as: (i) the total Lessor’s Cost of all Uncommitted Equipment does not at any time exceed Seven Million Five Hundred Thousand Dollars ($7,500,000); (ii) any Uncommitted Equipment is stored at a location acceptable to Lessor; (iii) Lessee will take all action reasonably requested by Lessor to assure that the Equipment will not be sold or encumbered by any Lien including marking such Equipment conspicuously as property of Lessor; (iv)

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Lessee shall be diligently pursuing a Permitted Use Agreement for such Equipment; and (v) no such Schedule reduces the Fleet Utilization Rate or Equipment Utilization Rate below the amount permitted under Section 10.2 hereof. Upon Lessor’s written approval of a Permitted Use Agreement for any Uncommitted Equipment as provided herein, Lessee may relocate such Equipment to the location set forth in such Permitted Use Agreement.

9.12 Opinion of Counsel. Lessor shall have received a written opinions of counsel to Lessee or bring down certificate if requested by Lessor, in the forms attached as Exhibit F-1 and Exhibit F-2.

9.13 Equipment; Purchase Agreement. The property which will constitute “Equipment” under the Schedule shall be new natural gas compressor packages equipped with engines manufactured by Caterpillar Inc. or such other equipment approved by Lessor, each acceptable to Lessor in its sole discretion; and Lessee and Vendor shall have entered into a Purchase Agreement which is reasonably acceptable to Lessor and satisfies the terms and conditions of this Lease, including Section 6.2(b) hereof.

9.14 Location. The location to be set forth in the Schedule as the location of the Equipment must be within the Continental United States and must not be offshore (but can be located in inland waters in Louisiana).

9.15 Lessor’s Cost. The Lessor’s Cost for such Schedule, when added to the sum of the Lessor’s Cost set forth on all other Schedules previously entered to in accordance with this Master Lease, shall not exceed Seventy-Five Million Dollars ($75,000,000.00).

9.16 Number of Schedules. There shall not be more than four (4) total Schedules entered into within the same calendar month.

9.17 Payment Factor. The payment factor to be used to determine the quarterly Rent shall have been agreed to by Lessor and Lessee.

9.18 Final Schedule Date. In Lessor’s opinion, the Base Term Commencement date for such Schedule will not be later than December 31, 2009.

9.19 Arrangement Fee; Schedule Commitment Fee. Lessee shall have paid Lessor: (a) a one-time, non-refundable Arrangement Fee equal to Two Hundred Fifty Thousand ($250,000) which shall be due and payable upon the execution of this Agreement and which shall be deemed earned by Lessor upon execution of this Master Lease; and (b) a non-refundable Schedule Commitment Fee equal to one and one-half percent (1.5%) of the Lessor’s Cost of each such Schedule (which shall be in addition to the Arrangement Fee) which shall be due and payable upon the execution of each Schedule and which shall be deemed earned by Lessor upon execution of each such applicable Schedule.

Any election by Lessor to lease the Equipment to Lessee prior to the fulfillment of any of the conditions precedent set forth in this Section 9 shall constitute only an extension of time for the fulfillment of such condition and not a waiver thereof, and Lessee shall use its best efforts to fulfill each such condition promptly.

Section 10. Additional Lessee’s Covenants. So long as Lessee shall have any unfulfilled or undischarged Obligations or duties under the Lease, Lessee will comply with the following requirements:

10.1 Financial Reporting. (a) Lessee shall keep its books and records in accordance with GAAP and shall deliver to Lessor: (i) its internally prepared quarterly financial statements within thirty (30) days of the end of each fiscal quarter; and (ii) the segment information for Lessee included in the in the public filings of the financial information filed by the Parent in accordance with Applicable Laws of the U.S. Securities and Exchange Commission within one hundred twenty (120) days of fiscal year end.

Lessee represents and warrants to Lessor that all credit, financial and other information submitted to Lessor shall be true, correct, and complete.

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10.2 Fleet Utilization Rate and Equipment Utilization Rate.

(a) The Fleet Utilization Rate shall not fall below eighty percent (80%) during the Term. The “Fleet Utilization Rate” means the average fleet utilization for the three consecutive fiscal months ending as determined on the last day of such fiscal quarter which shall be calculated as (i) the total horsepower of Lessee’s Eligible Gas Compressor Packages that is being furnished to a Person pursuant to services agreements, or other contractual arrangements in Lessee’s ordinary course of business, to (ii) the total sum of all idle, owned, and leased horsepower of Lessee’s Eligible Gas Compressor Packages. As used herein, “Eligible Gas Compressor Packages” means gas compressor packages and related equipment, whether or not subject to this Lease, which in Lessor’s reasonable judgment are in good, undamaged condition and are not obsolete or otherwise unmarketable in the ordinary course of business as a result of age, type, category, quality and/or quantity.

(b) Without in any way limiting Section 10.2(a) above: (i) on June 30, 2010, the Equipment Utilization Rate shall be equal to or greater than ninety percent (90%); and (ii) at all times thereafter, the Equipment Utilization Rate shall not fall below eighty percent (80%) during the Term. The “Equipment Utilization Rate” shall mean the ratio of: (A) the total horsepower of all Equipment subject to this Lease that is being furnished to a Person pursuant to a Permitted Use Agreement, to (B) the total horsepower of all Equipment subject to this Lease, whether or not furnished to a Person pursuant to a Permitted Use Agreement.

(c) Lessee shall provide Lessor on or before the thirtieth (30th) day of the month following each fiscal quarter with a certificate of Vice President of Lessee in form and substance reasonably satisfactory to Lessor, setting forth the Fleet Utilization Rate and Equipment Utilization Rate at the end of the previous fiscal quarter.

10.3 Merger; Change of Control.

(a) Lessee shall obtain the prior written consent of Lessor (which such consent shall not be unreasonably denied, withheld, conditioned or delayed) at least forty-five (45) days prior to the occurrence of a Change of Control of Lessee. As used herein “Change of Control” of a Person shall mean, as the result of a single or series of transactions, directly or indirectly (A) any acquisition of such Person or its capital stock, membership interests or other ownership interests by means of purchase, merger, tender offer, reorganization, business combination, consolidation or other event in which the Substantial Majority (as defined below) of the voting power of the then outstanding capital stock, membership interests or other ownership interests of such Person entitled to vote at the election of the Board of Directors, Managers or other senior management of such Person is transferred, (B) such Person acquires through any purchase, merger, tender offer, reorganization, business combination, consolidation or other event the majority of the voting power of the then outstanding capital stock, membership interests or other ownership interests of any Person entitled to vote at an election of the Board of Directors, Managers or other senior management of such Person, or (C) any sale or other disposition of all or substantially all of Borrower’s assets. As used herein, “Substantial Majority” means fifty-one percent (51%) or such other percentage as Lessor shall reasonably determine to be a material to Lessee’s business, financial condition or ability to perform any obligation to Lessor hereunder.

(b) If Lessor does not consent to a Change of Control within ten (10) Business Days after its receipt of a request for such consent, or if Lessor denies such request in writing, Lessee may elect by giving Lessor written notice (which notice shall be irrevocable without Lessor’s written consent) to purchase all, but not less than all, Equipment leased on each and every Schedule to this Master Lease an amount equal to the greater of: (i) the Casualty Value of the Equipment; or (ii) the Fair Market Purchase

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Value of the Equipment, in either case together with all other amounts due under such Schedule with respect to such Equipment plus applicable Taxes and other amounts due or payable with respect to such sale. Such purchase option may only be exercised upon twenty (20) Business Days written notice, on the earlier of the (i) effective date of the Change of Control, or (ii) the date that the next payment of Rent is due hereunder. All Equipment shall be sold to Lessee on an AS IS, WHERE IS BASIS, without recourse or warranty (except that Lessor shall represent that it has whatever title (if any) to the Equipment that was conveyed to it by the Vendor free of any security interest arising solely by reason of a claim against Lessor that Lessee is not responsible to remove pursuant to this Lease).

(c) As used herein, the term “Fair Market Purchase Value” means the purchase price of the Equipment as determined on the basis of, and will be equal in amount to, the value which one would obtain in an arm’s-length transaction between an informed and willing buyer (other than a lessee currently in possession and a used equipment dealer) and an informed and willing seller under no compulsion to sell and, in such determination it will be assumed that the Equipment is in the condition required to be maintained and returned under this Lease and is value on an installed basis and the costs of removal from current location shall not be a deduction from such valuation. For purposes of this Master Lease, the Fair Market Purchase Value for the Equipment shall be determined by mutual agreement of Lessor and Lessee. If such mutual agreement cannot be reached, then it shall be determined by the Appraisal Process. Until such time as Lessee pays Lessor the Fair Market Purchase Value, is shall continue pay Rent and perform its other obligations hereunder.

(d) Without in any way limiting its rights against Lessee hereunder, Lessor expressly acknowledges and agrees that: (i) nothing in this Section 10.3 shall in any way prevent a Change of Control with respect to Parent; and (ii) Parent shall not have any obligations under this Section 10.3.

10.4 Customer Concentration. Except for Persons set forth on Exhibit C, no single Person shall be the Permitted User for more than twenty percent (20%) of the Equipment leased under all Leases hereunder. This test shall be applied on a quarterly basis and shall not apply until the original Lessor’s Cost of all Schedules entered to in accordance with this Master Lease exceeds Twenty Million Dollars ($20,000,000). Each person set forth on Exhibit C shall have publicly available financial information and none shall account for more than Thirty-Five Million Dollars ($35,000,000) in Equipment leased under this Agreement.

10.5 Total Debt to EBITDAR. The Ratio of Lessee’s Total Debt to EBITDAR shall at all times be less than or equal to Four to One (4:1). As used herein: (a) “Total Debt” shall mean the sum of Lessee’s Indebtedness and Lessee’s obligations under any and all operating leases; (b) “Indebtedness”, for purposes of this Section 10.5, shall have the meaning ascribed thereto in that certain Fourth Amended and Restated Credit Agreement, dated as of December 1, 2004, among Regency Gas Services, LP, Parent and other parties set forth therein, as amended pursuant to Amendment Agreements No. 1 through 6, inclusive (the “RGS Credit Agreement”), which such definition: (i) is hereby incorporated by reference and made a part hereof as if fully set forth herein; and (ii) shall not be amended, modified, terminated or otherwise changed by virtue of any amendment, modification or termination of the RGS Credit Agreement, it being the intention of the parties that the definition as set forth in the RGS Credit Agreement as of the Amendment Agreement No. 6, dated as of May 9, 2008, shall be the definition for all purposes hereunder; (c) “EBITDAR” shall mean (i) Net Income for such period plus (ii) to the extent deducted in determining such Net Income (A) Interest Expense for such period, (B) taxes due on such Net Income for such period; (C) depreciation for such period; (D) amortization for such period; and (c) rent and lease expense for such period; (d) “Interest Expense” shall mean, with respect to any Person, for any period, the interest payable by such Person on indebtedness, including money borrowed and capitalized lease obligations, determined in accordance with GAAP; and (e) “Net Income” shall mean, with respect to any Person, for any period, the aggregate of the net income of such Person determined in accordance with GAAP. Lessee’s breach of its covenant in this Section 8.19 shall be an immediate Event of Default. Such ratio shall be measured on the basis of Lessee’s audited financial statements or such other information as Lessor shall select.

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10.6 Permits and Related Rights. Lessee hereby agrees to obtain, secure, and maintain any and all Permits and Related Rights.

10.7 Applicable Laws. Lessee shall comply with all Applicable Laws including all laws, statutes, regulations and ordinances regarding the collection, payment and deposit of employees’ income, unemployment, social security, sales and excise taxes, and other Taxes, the noncompliance with which would have a material adverse effect on the business, property or financial condition of Lessee, and shall also comply with, perform and observe all material covenants, provisions and conditions in connection with all other loan or credit agreements to which it or any subsidiary is a party.

10.8 Environmental Laws. Lessee shall comply with all Environmental Laws in connection with the operation and use of the Equipment, including Environmental Laws relating to the storage and disposal of Hazardous Materials.

10.9 Taxes. Lessee shall timely file all federal, state and local tax returns or extensions and other reports Lessee or its subsidiary is required by law to file, and maintain adequate reserves for the payment of all Taxes, assessments, governmental charges and levies imposed upon it, its income, or its profits, or upon any property belonging to it. Lessee shall pay and discharge all Taxes upon it, its income and properties as and when such Taxes are due and payable, except and to the extent only that such Taxes are being actively contested in good faith and by appropriate proceedings, Lessee promptly notifies Lessor in writing of any such contest relating to the equipment, Lessee maintains adequate reserves on its books or otherwise allows therefore, and the nonpayment of such Taxes does not result in a Lien upon the Equipment. Lessee shall also pay and discharge any lawful claims which, if unpaid, might become a Lien against the Equipment.

10.10 Additional Documents. At Lessor’s request, Lessee shall promptly execute or cause to be executed and delivered to Lessor any and all documents, instruments and agreements reasonably deemed necessary by Lessor to give effect to or carry out the terms or intent of this Lease or any of the other Lease Documents which derive from or relate to any directives, requests, laws, regulations or other similar requirements of any Governmental Authority, agency or instrumentality of the United States of America or any subdivisions thereof.

10.11 Representations, Warranties, Agreements and Covenants. All representations, warranties, agreements and covenants made by Lessee herein or in the Lease Documents shall be true, correct and complete in all material respects and shall be considered to have been relied upon by Lessor and shall survive the making of this Lease regardless of any investigation made by or on behalf of Lessor.

Section 11. Assignment; Sublease.

(a) WITHOUT LESSOR’S PRIOR WRITTEN CONSENT, LESSEE SHALL NOT (i) SELL, ASSIGN, SUBLEASE OR OTHERWISE TRANSFER ANY PART OF THE EQUIPMENT OR ANY OF ITS INTEREST IN OR RIGHTS UNDER THIS LEASE OR AS TO ANY PART OF THE EQUIPMENT (INCLUDING BY OPERATION OF LAW, EXCEPT TO THE EXTENT ALLOWED IN ACCORDANCE WITH SECTION 10.3 HEREOF) OR (ii) ENCUMBER OR PERMIT ANY LIEN (OTHER THAN LIENS IN FAVOR OF LESSOR) TO EXIST AGAINST ANY PART OF THE EQUIPMENT OR LESSEE’S INTEREST IN THIS LEASE, IT BEING LESSEE’S UNDERSTANDING THAT ANY SUCH ACTION, EVENT OR OCCURRENCE SHALL CONSTITUTE AN IMMEDIATE EVENT OF DEFAULT HEREUNDER GIVING LESSOR THE RIGHT TO TERMINATE OR CANCEL THIS LEASE AND EXERCISE ITS REMEDIES HEREUNDER.

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(b) NOTWITHSTANDING SECTION 11(a), LESSOR SHALL CONSENT TO LESSEE’S PROVIDING OF THE EQUIPMENT TO PERMITTED USERS ONLY IN ACCORDANCE WITH THE TERMS OF A PERMITTED USE AGREEMENT. Lessee further represents, warrants, covenants and agrees to Lessor that (i) all of its obligations under this Lease shall continue to be Lessee’s primary obligations and shall not be diminished or vitiated in any way by virtue of such Permitted Use Agreements; (ii) the terms and conditions of each Permitted Use Agreement shall in no way conflict with the terms and conditions of this Lease and shall in no way render performance by Lessee of such terms and conditions more difficult; (iii) Lessee’s obligations under each Permitted Use Agreement, are Lessee’s sole responsibility and Lessor shall have no obligations thereunder and each Permitted User shall look solely to Lessee and not to Lessor for the performance of Lessee’s obligations under each Permitted Use Agreement; and (iv) to the extent that any provision of the Permitted Use Agreement conflicts with any of Lessor’s rights under this Lease, such Permitted Use Agreement provision shall be of no effect.

(c) Lessor may at any time with or without notice to Lessee grant a Lien on, sell, assign, delegate or otherwise transfer (any of the foregoing, a “Lessor Assignment”) all or any part of its interest in the Equipment, any Lease or any Schedule and any related Lease Documents or any Rent thereunder to any third party that is not a competitor of Lessee in the natural gas compression business listed on an Exhibit E (each, a “Lessor Assignee”) and Lessee shall perform all of its obligations thereunder, to the extent so transferred, for the benefit of each such Lessor Assignee. Lessee agrees not to assert against any Lessor Assignee any Abatement (without limiting the provisions of Section 4.4) that Lessee may have against Lessor, and Lessor Assignee shall not be bound by, or otherwise required to perform any of Lessor’s obligations, unless expressly assumed by such Lessor Assignee. Lessor shall be relieved of any such obligations assumed by Lessor Assignee. If so directed in writing, Lessee shall pay all Rent and all other sums that become due under an assigned Lease, Schedule, and/or other Lease Document, directly to the Lessor Assignee or any other party designated in writing by Lessor or such Lessor Assignee. Lessee acknowledges that Lessor’s right to enter into a Lessor Assignment is essential to Lessor and, accordingly, waives any restrictions under Applicable Law, if any, with respect to a Lessor Assignment and any related remedies. Upon the request of Lessor or any Lessor Assignee, Lessee also agrees (i) to promptly execute and deliver to Lessor or to such Lessor Assignee an acknowledgment of the Lessor Assignment in form and substance satisfactory to the requesting party, an insurance certificate and such other documents and assurances reasonably requested by Lessor or Lessor Assignee, and (b) to comply with all other reasonable requirements of any such Lessor Assignee in connection with any such Lessor Assignment.

(d) Subject always to the foregoing, this Master Lease and each Schedule and other Lease Document shall inure to the benefit of, and are binding upon, Lessee’s and Lessor’s respective successors and assigns.

Section 12. Taxes. Lessee shall promptly pay all Taxes levied by any taxing authority upon this Lease, the Equipment or any other Lease Document or upon Lessor in connection herewith (including any Taxes related to the use of the Equipment) from the date any item or component of the Equipment is delivered until it is returned to Lessor. Lessee shall prepare and file, in a manner satisfactory to Lessor, any reports or returns which may be required with respect to the Equipment. For purposes of this Section 12, “Lessor” shall include any affiliated group, within the meaning of Section 1504 of the Code, of which Lessor is a member for any year in which a consolidated or combined income tax return is filed for the affiliated group. Lessee further agrees to pay all amounts owing by it under this Lease or the other Lease Documents free and clear of and without deduction for any present or future Taxes, and further agrees that: (a) if it is prevented by operation of law from paying any Taxes, then the fees required to be paid under this Lease or the other Lease Documents shall be increased by the amount necessary to yield to Lessor the Rent or fees at the rates specified in this Lease or the other Lease Documents after provision for the payment of all such Taxes and without taking into account any tax benefits accruing to Lessor from such payment (and shall, at the request of Lessor, execute and deliver to Lessor such further instruments as may be necessary or desirable to effect the increase in the Rent or fees as provided for herein); (b) it

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shall hold Lessor harmless from and against any liabilities with respect to any Taxes (whether or not properly or legally asserted); and (c) it shall provide Lessor with the original or a certified copy of evidence of the payment of any Taxes by it, as Lessor may reasonably request, or, if no Taxes are to be paid, to provide to Lessor, at Lessor’s request, a certificate from the appropriate taxing authority or an opinion of counsel acceptable to Lessor stating that no Taxes are payable. If Lessor shall receive a refund of any Taxes paid by Lessee pursuant to this Section 12 by reason of the fact that such Taxes were not correctly or legally asserted, Lessor shall within thirty (30) days after receipt of such refund pay to Lessee the amount of such refund, as determined solely by Lessor; provided, however, that in no event shall the amount paid by Lessor to Lessee pursuant to this Section 12 exceed the amount of Taxes originally paid by Lessee. Notwithstanding anything to the contrary herein, Lessor shall not have any obligation under this Lease to claim or otherwise seek to obtain any refunds but shall cooperate with Lessee with respect to any and all reasonable attempts by Lessee to obtain any such refunds. All of the foregoing obligations which relate to occurrences or events during the Term of this Lease are continuing and shall survive expiration, termination, or cancellation hereof.

Section 13. Loss or Damage; Indemnification

13.1 Casualty Occurrence. Lessee shall bear the risk if a Casualty Occurrence or other damage occurs to the Equipment from the date of the Master Lease until all Obligations have been satisfied. Lessee shall give Lessor prompt notice of a Casualty Occurrence or other damage to the Equipment which does not constitute Reasonable Wear and Tear. If, in Lessor’s opinion, any damage to the Equipment is not a Casualty Occurrence, Lessee shall, at its expense, promptly restore the Equipment to the condition required herein. If the damage is a Casualty Occurrence, Lessee shall pay to Lessor on the first Rent payment due date following the Casualty Occurrence (thirty (30) days after the Casualty Occurrence if there is no Rent payment due date remaining) all amounts then due under this Lease with respect to the item or component of the Equipment suffering said Casualty Occurrence (the “Casualty Impaired Equipment”), plus a sum equal to the applicable Casualty Value of the Casualty Impaired Equipment, as applicable. Upon making this payment, the Term with respect to the Casualty Impaired Equipment shall terminate and Lessee shall be entitled to possession of the Casualty Impaired Equipment and shall be responsible for its sale or other disposition. Lessee shall be entitled to any recovery from insurance or otherwise, related to the Casualty Impaired Equipment to the extent it exceeds the amount of the Casualty Value paid by Lessee.

13.2 General Indemnity. Lessee hereby agrees to defend, indemnify and hold Lessor (and at Lessor’s option, Lessor’s employees, agents, directors, partners, shareholders, officers, members and any assignee or secured party)(the “Lessor Indemnified Parties”), harmless from and against (a) all claims, demands, suits and legal proceedings (whether civil, criminal, administrative, investigative or otherwise), including arbitration, mediation, bankruptcy and appeal and including any claims, demands suits and legal proceedings (i) arising out of the actual or alleged manufacture, purchase, financing, ownership, delivery, rejection, non-delivery, possession, use, rental, transportation, storage, operation, maintenance, repair, return or other disposition of the Equipment or any part of the Equipment, (ii) by any Governmental Authority or any third party under any Environmental Law, under any common law tort claim theory applicable to Hazardous Materials or any Hazardous Materials remediation otherwise required to be performed or conducted under any applicable Environmental Law; (iii) patent, trademark or copyright infringement; (iv) related to or arising out of or in connection with any Permitted Use Agreement, (v) related to any actual default by Lessee of this Lease or any other Lease Document; and (vi) related to any default under this Lease or any other Lease Document reasonably alleged by Lessor (whether or not such occurrence, act of failure to act, constitutes an actual default) (collectively, “Actions”); and (b) any and all penalties, losses (including Environmental Losses), liabilities (including the liability of Lessee or Lessor for negligence, tort and strict liability), damages, costs, court costs and any and all other expenses (including Attorneys’ Fees, judgments and amounts paid in settlement), related to, arising out of or in any way connected with any Actions. Lessee shall, at Lessor’s option, appear and defend any such Action and

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pay the cost of the defense of any such action brought against Lessor, either alone or in conjunction with others, upon any such liability or claim. Lessee shall satisfy, pay, and discharge any and all judgments and fines that may be recovered against Lessor in any such action. Notwithstanding the foregoing, Lessee does not have to indemnify any Lessor Indemnified Parties to the extent damages otherwise covered under this Section XI are adjudged by a court of competent jurisdiction to have been the result of the gross negligence or willful misconduct of any of the Lessor Indemnified Parties so long as the Actions are not asserted on the basis of (A) theories of vicarious liability, including agency, apparent agency or employment; (B) theories that any Lessor Indemnified Parties negligently entrusted the Equipment to Lessee, any Permitted User any other third party using the Equipment by or through Lessee or such Permitted User; or (C) the failure of any Lessor Indemnified Parties to compel Lessee to comply with the provisions of this Lease. The foregoing Indemnities are continuing indemnities and shall survive expiration, termination or cancellation

13.3 Tax Indemnity.

(a) Lessor and Lessee hereby agree that: (i) the Equipment constitutes depreciable personal property used in a trade or business; and (ii) Lessor is entitled to such deductions, credits and other tax benefits as are or may be allowed under the Internal Revenue Code of 1986, as amended (the “Code”) or under any state or local income tax laws, to the owner of depreciable personal property used in a trade or business. Except as otherwise provided herein and without limiting the foregoing, Lessor shall be entitled to all tax benefits generally available to owners and lessors of business equipment including (A) the MACRS deductions for each item of Equipment allowable under Section 168 of the Code (together with corresponding deductions under applicable state law, the “MACRS Deductions”) computed on a basis equal to Lessor’s Cost for such Equipment and the MACRS period assumed by Lessor in calculating Rent; (B) the deduction under Section 163 of the Code (the “Interest Deductions”) with respect to interest paid by Lessor on any indebtedness incurred by Lessor in financing its purchase of the Equipment; and (C) Lessee shall prevent the Equipment from being used in any manner that would diminish its depreciable life.

(b) If all or any portion of Lessor’s share of MACRS Deductions, Interest Deductions or other tax benefits associated with the ownership of the Equipment (the MACRS Deduction, Interest Deduction and other tax benefits being herein called the “Tax Benefits”) is reduced for any year or reporting period, disallowed, or denied, or if any Tax Benefit is recaptured, with respect to any item of Equipment (a “Disallowance”), or if any modification, Improvement or use of any item shall result in the realization of income by Lessor for federal or state income tax purposes (an “Inclusion”), the Rent for such Equipment shall be increased by an amount that, in the reasonable opinion of Lessor, will cause Lessor’s anticipated cash flow and after-tax return over the Term for such Equipment to equal Lessor’s cash flow and such after-tax return that would have been obtained had such Disallowance or Inclusion had not occurred. After the occurrence of a Disallowance or Inclusion, Lessor shall provide Lessee written notice of such Disallowance or Inclusion, which notice shall contain the amount of any increase in Rent resulting from the Disallowance or Inclusion. The Rent for such Equipment shall be increased by the amount stated in such written notice to Lessee as of the date of such notice. If any Disallowance or Inclusion occurs after the expiration of this Lease, Lessee hereby agrees to and shall indemnify Lessor for the full amount of any such Disallowance or Inclusion upon demand of Lessor. At Lessor’s election, Lessee shall pay to Lessor an amount that, after deduction of all taxes payable by reason of payment under this Section 13.3, compensates Lessor fully for such Disallowance or Inclusion.

(c) A Disallowance or Inclusion shall be deemed to occur upon the earliest of: (i) the happening of any event or condition (such as disposition or change in use of any item of Equipment) that shall cause such Disallowance or Inclusion; (ii) the payment by Lessor to the Internal Revenue Service or any state or local taxing authority of the tax increase resulting from such Disallowance or Inclusion; (iii) the adjustment of the tax return of Lessor to reflect such Disallowance or Inclusion; or (iv) Lessor’s receipt of

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written advice from its legal or tax advisers that a payment or Inclusion as contemplated by this Section 13.3 is required. The occurrence of a Disallowance or Inclusion and the amount payable to Lessor under this Section 13.3 shall be calculated by certified public accountants selected by Lessor, and such calculation shall be binding and conclusive on Lessor and Lessee.

(d) Lessee and Lessor hereby agree that if, after the date of this Lease, there is any change in the Code or the regulations promulgated hereunder, or in any state or local income tax laws or regulations (including the introduction of any new income tax law or any change in the maximum marginal federal, state or local income tax rate from time to time applicable to corporations or limited partnerships) that would reduce the after-tax return that Lessor would have obtained if such change in law or regulation had not occurred, the Rent specified in this Lease shall be increased by an amount that, in the reasonable opinion of Lessor, will cause Lessor after-tax return over the Term specified in this Lease to equal the after-tax return that Lessor would have obtained if such change in law or regulation had not occurred (the “Adjusted Payment”). After such a change in law or regulation, Lessor shall provide Lessee written notice of such change in law or regulation, which notice shall contain the amount of any increase in Rent as the result of this paragraph. Rent shall be increased by the amount stated in such written notice to Lessee as of the date specified in such notice as the date the Adjusted Payment becomes effective. It is the express intent and purpose of this paragraph to allocate to Lessee all risk resulting from any change in law or regulation that would have the effect of reducing Lessor after-tax return resulting from the purchase of the Equipment and the leasing thereof to Lessee hereunder. The Indemnities set forth in this Section 13.3 are continuing indemnities and shall survive expiration, termination, or cancellation.

Section 14. Insurance.

14.1 Insurance Policies. Lessee, shall maintain, or cause to be maintained, at no expense to Lessor, the following insurance:

(a) All-Risk first party property insurance covering the Equipment for any physical loss or damage to the Equipment (or any portion thereof), including loss or damage caused, in whole or in part, by fire, water, wind, collapse, theft, vandalism, malicious mischief, collision and other risks normally included in extended All-Risk property coverage in an amount not less than greater of: (i) the full replacement cost of the Equipment, and (ii) the Casualty Value of the Equipment

(b) A Comprehensive Liability Insurance Policy in form and substance acceptable to Lessor and including a waiver of subrogation endorsement in favor of Lessor. The Comprehensive Liability Insurance Policy must be written with a limit of liability satisfactory to Lessor in its sole and absolute discretion covering all sums Lessee and/or Lessor shall become legally obligated to pay as damages for bodily injury, including bodily injury, sickness, disease or death, or property damage, including loss of use, arising, directly or indirectly, in connection with the Equipment, including contractual liability coverage in support of Lessee’s indemnification agreements in favor of Lessor.

(c) Workers’ Compensation Insurance Policies covering Lessee’s employees in an amount not less than the statutory limits for the State of where the Equipment is located (as may be amended from time to time), including Employer’s Liability Insurance with limits of liability of not less than (i) One Million Dollars ($1,000,000) for bodily injury by accident, each accident, (ii) One Million Dollars ($1,000,000) for bodily injury by disease, each employee, and (iii) One Million Dollars ($1,000,000) aggregate liability for disease. The Workers’ Compensation & Employer’s Liability Insurance Policies must each include a waiver of subrogation endorsement in favor of Lessor.

(d) Excess Liability Insurance, if any is provided by Lessee in satisfaction of its obligations hereunder or is required by Lessor in its sole and absolute discretion , shall specifically identify each of the policies described above in (a) and (b) of this Section 14.1 on the Schedule of Underlying Coverages, and shall provide and include as insured any party insured under the policies described above, coverage that follows the form of each of the underlying policies.

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14.2 Additional Insurance Provisions. All policies shall include Lessor and such other parties as Lessor may designate and their respective officers, directors, partners, employees, agents, and consultants as loss payees and additional insureds to the insurance policies described below (excluding the Liability and Workers’ Compensation Policies). The insurance coverage afforded under the policies described herein shall be primary and non-contributing with respect to any insurance carried independently by the additional insureds. All such insurance policies shall indicate that as respects the insureds (whether named or otherwise), cross-liability and severability of interests shall exist for all coverages provided thereunder. All policies of insurance required under this Section 14 shall be written on an “occurrence” basis except as otherwise agreed by Lessor in its sole and absolute discretion. The insurance specified below shall be placed with insurance companies reasonably acceptable to Lessor (which companies shall, at a minimum, have a rating of “B+10” or better by A.M. Best Company unless otherwise agreed by Lessor), and shall incorporate a provision requiring the giving of notice to Lessor at least thirty (30) days prior to the cancellation, non-renewal or material modification of any such policies. Upon execution hereof, and periodically thereafter, including upon renewal, as required to demonstrate that insurance coverage is in effect, Lessee shall provide to Lessor, certified copies of all certificates with respect to insurance required under this Section 14, stating the name of insurance company, policy number, expiration date, that Lessor is named as additional insured and loss payee (where applicable), and the coverage and limits of liability with respect to each such insurance policy, all in a form reasonably acceptable to Lessor. All dollar amounts expressed in this Section 14 or approved by Lessor shall be updated every five (5) years based on the then-current market conditions. Lessee shall not make adjustments in amounts greater than $100,000 with insurers except with Lessor’s prior written consent and hereby appoints Lessor as Lessee’s attorney-in-fact to receive payment of and to endorse all checks, drafts and other documents and to take any other actions necessary to pursue insurance claims and recover payments pursuant to the insurance policies required hereunder if Lessee fails to do so (this power being coupled with an interest and irrevocable for the term of this Lease). Lessee shall promptly notify Lessor of any occurrence which may become the basis of a claim and shall provide Lessor with all requested pertinent data.

Section 15. Default

15.1 Event of Default. Each of the following constitutes an event of default (“Event of Default”) hereunder: (a) Lessor does not receive any Rent or other payment due hereunder within five (5) days of such payment’s due date; (b) Lessee fails (i) to provide Lessor with any notice required hereunder or (ii) to maintain insurance in accordance with Section 14 of this Lease; (c) Lessee breaches its obligations under Section 11 of this Lease; (d) any default occurs under any Lease Document; (e) any default by Lessee occurs under any Permitted Use Agreement provided, however that, it shall not be an Event of Default for an additional thirty (30) days so long as Lessee is diligently attempting to remedy the default under the applicable agreement or enter into a substitute agreement in form and substance satisfactory to Lessor; (f) Lessee ceases to do business, becomes insolvent, makes an assignment for the benefit of creditors or files any petition or action under any bankruptcy, reorganization, insolvency or moratorium law, or any other law or laws for the relief of, or relating to, debtors; (g) Lessee changes its legal name, state of organization, organizational structure or organizational identification number and fails to give written notice thereof to Lessor within thirty (30) days following the occurrence of the same; (h) Lessee, or any other party acting on Lessee’s behalf, files, communicates or records, or attempts to file, communicate or record, a termination statement under Article 9 of the UCC without the prior written consent of Lessor; (i) Lessee fails to observe or perform any covenant, agreement, or warranty made by Lessee in this Lease and the failure continues for ten (10) days after Lessor provides written notice thereof to Lessee; (j) Lessee or Parent defaults under any agreement for money borrowed or the lease of real or personal property, which default Lessor reasonably determines, taking into account all relevant facts and

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circumstances known to Lessor including the nature and amount of financial exposure, would have a material adverse effect on: (A) Lessee’s ability to pay or perform its Obligations; (B) Lessee’s ability to perform its duties under the Permitted Use Agreements or to receive any payments due to Lessee thereunder; (C) the business, assets, operations or financial or other condition of Lessee; or (D) Lessor’s rights hereunder; (k) the filing of an involuntary petition under any bankruptcy statute against Lessee, or appointment of a receiver, trustee, custodian or similar official to take possession of the properties of Lessee, unless the petition or appointment ceases to be in effect within thirty (30) days after filing or appointment; (l) the Property is condemned by any Governmental Authority; (m) Lessee shall be nationalized or any government or any agency thereof exercises management control of Lessee’s day-to-day business operations and affairs; (n) any representation of Lessee under the Lease is false in any material respect; or (o) Lessee suffers a Change of Control as to which it has not received Lessor’s consent as provided in Section 10.3. Lessee acknowledges that an Event of Default under any Lease shall constitute an Event of Default under all Leases.

15.2 Remedies. Upon the occurrence of any Event of Default, Lessor shall have any and all remedies existing at law, or in equity, and shall have the right, at its sole option, at any time to exercise any or all of such remedies concurrently, successively or separately, without notice to Lessee (unless specifically stated herein). Without limiting its right to seek any and all remedies existing, upon the occurrence of an Event of Default, Lessor, in its absolute and sole discretion, may: (a) proceed by court action to enforce performance by Lessee of the covenants and terms of this Lease; (b) require Lessee to make the Equipment available to Lessor pursuant to Section 5.4 hereof; (c) immediately and without legal proceedings or notice or liability to Lessor, enter the premises, take possession of or remove and retain or make inoperable the Equipment or any component thereof (any such taking shall not terminate this Lease), full and complete license to do so being hereby expressly granted by Lessee to Lessor; (d) declare the entire amount of Rent and other sums payable hereunder immediately due and payable; (e) by written notice to Lessee, terminate this Lease, in which event all rights of Lessee to use the Equipment shall terminate; provided, however, that in such event Lessee shall remain liable for all damages as provided herein and provided, further that no notice shall be required upon the occurrence of an Event of Default under Section 15.1(f) or (m) hereof and such remedy shall be automatic; and/or (f) recover, as damages for loss of the bargain and not as a penalty, the sum of (i) any accrued and unpaid Rent and other amounts due hereunder, plus (ii) the Casualty Value of the Equipment, plus (iii) an amount reasonably calculated by Lessor to give Lessor all of the benefits of its interest in this Lease and amounts payable hereunder but for such Event of Default, including Tax Benefits Rent; plus (iii) any other damages incurred by Lessor on account of, or otherwise relating to, the breach of any covenant, representation or warranty by Lessee herein, plus (iv) all fees, costs or expenses incurred by Lessor in connection with any repossession, recovery, storage, repair, sale, re-lease or other disposition of the Equipment, including all Attorneys’ Fees and costs incurred by Lessor in connection therewith or otherwise resulting from Lessee’s default or enforcement of this Lease (including any such fees or costs incurred at trial or in any other proceeding), or any other reasonable professional fees and costs. Lessor shall have no liability by reason of any entry, repossession, or removal of all or any portion of the Equipment performed in accordance with Applicable Law. Upon the written demand of Lessor, Lessee shall return the Equipment promptly to Lessor, in the manner and condition required by, and otherwise in accordance with the provisions of, Section 5.4 hereof.

15.3 Permits and Related Rights. Lessee authorizes and directs the issuing agency, whether city, county, state or federal, to reassign the Permits and Related Rights to Lessor or its designees upon notification by Lessor that an Event of Default has occurred and Lessee herein releases the issuing agent, upon assignment or transfer by the issuing agent to Lessor or its designee, from any claims, actions, demands, and suits of any nature whatsoever arising from said transfer or assignment.

15.4 Lessor Right to Perform. If Lessee fails to perform any of its Obligations under this Lease, Lessor, in its sole and absolute discretion, may perform any such or all of the Obligations, and the expenses incurred by Lessor as a result thereof shall be payable by Lessee upon demand. In no event shall Lessor be obligated to perform any of Lessee’s Obligations with respect to this Lease.

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15.5 Repayment; Setoff. Lessee hereby grants Lessor and Lessor’s successors and assigns (including any affiliate or subsidiary of Lessor) the right to apply, at any time and from time to time should an Event of Default exist hereunder, any and all obligations owing from Lessor (or its assignees hereunder) to Lessee toward repayment of any sums owing from Lessee to Lessor hereunder. Lessee shall not have any right of setoff and hereby waives any such right of setoff or reduction due to any reason whatsoever.

15.6 Cumulative Remedies. The remedies provided to Lessor shall be cumulative and shall be in addition to all other remedies existing at law or in equity.

Section 16. Miscellaneous

16.1 Further Assurances; Power of Attorney. Lessee will, upon demand of Lessor, at Lessee’s sole cost and expense, do and perform any other act and will execute, acknowledge, deliver, file, register, communicate, record and deposit (and will re-file, re-register, re-communicate, re-record or re-deposit whenever required) any and all further documents, instruments or records required by law or reasonably requested by Lessor including financing statements or other records under the UCC as currently in force or as subsequently revised or re-enacted, mortgages and other recordations (which Lessor shall have the right to file, communicate or record wherever and whenever Lessor deems prudent for the purpose of proper protection, to the satisfaction of Lessor, of Lessor’s title and precautionary security interest in the Equipment or to carry out the provisions of this Lease.) Lessee further authorizes Lessor, and irrevocably appoints Lessor as its attorney-in-fact (coupled with an interest) to enter ministerial information on any Schedule or other writing executed in connection with the Lease, to file financing statements or to execute and deliver or otherwise authenticate and communicate any writing or record and take any other actions that Lessor reasonably deems necessary or desirable or protect Lessor’s interest in the Equipment and under this Lease or any other Lease Document. Lessee further authorizes Lessor to transmit and file any such statements, ministerial changes, and other items by electronic means.

16.2 No Merger of Title. There shall be no merger of this Lease or of the leasehold estate created hereby by reason of the fact that the same Person may acquire, own or hold, directly or indirectly, in whole or in part, (a) this Lease or the leasehold estate created hereby or any interest in this Lease or such leasehold estate, or (b) any right, title or interest in the Equipment.

16.3 Effect of Delay. A delay or omission by Lessor to exercise any right, power or remedy hereunder shall not impair the right, power or remedy and shall not be construed to be a waiver of any breach or default. Any waiver or consent by Lessor of or to any breach or default must be in writing.

16.4 Severability and Survival. If any provision of this Lease shall be invalid under any Applicable Law, it shall be inapplicable and deemed omitted but the remaining provisions shall be given effect in accordance with the intent of the Lease. All Obligations of Lessee under this Lease and the Lease Documents shall survive the expiration or termination of this Lease to the extent required for their full observance and performance.

16.5 Amendment or Modification of Lease. The terms of this Lease may not be amended, waived, modified, or terminated except by written instrument signed by the parties hereto. No such amendment or waiver shall extend to or affect any Obligation not expressly amended or waived or impair any right consequent thereon. In the event an amendment to any of the Lease Documents is required, in Lessor’s sole discretion, due to any request, action or inaction of Lessee, including any voluntary or mandatory prepayment of the payment obligations, Lessee shall reimburse Lessor for all costs and expenses associated with such amendment, including the reasonable fees and out-of-pocket expenses of outside counsel for Lessor and the reasonable travel costs of Lessor’s in-house counsel with respect thereto.

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16.6 Costs and Expenses. Lessee agrees to pay all costs and expenses in connection with the preparation, execution, delivery and enforcement of this Lease and any other documents to be delivered hereunder, including the reasonable fees and out-of-pocket expenses of outside counsel for Lessor and the travel costs of Lessor’s in-house counsel (excluding any internal allocated charges of Lessor’s in-house counsel) with respect thereto and with respect to advising Lessor as to its rights and responsibilities under this Lease and the other Lease Documents. Lessee also agrees to pay on demand all losses, costs and expenses, if any (including any and all fees and out-of-pocket expenses of counsel and Lessor’s engineer, including travel costs), incurred in connection with the preservation of any rights of Lessor under, or the enforcement of, or legal advice in respect of, the rights or responsibilities of Lessor under this Lease or the Lease Documents, including losses, costs and expenses sustained by Lessor as a result of any failure by Lessee to perform or observe its Obligations contained herein or any other document related hereto.

16.7 Interpretation. Any use of the term “Equipment” herein shall be deemed to refer equally to the Equipment and all other parts of the Equipment, it being the understanding of the parties that any reference to “Equipment” shall not be deemed to prejudice any right of Lessor hereunder to require performance as to each and every part of the Equipment and any reference to “Equipment” shall not be deemed to prejudice any right of Lessor to require performance as to all of the Equipment. All references to Sections herein, unless otherwise stated, shall refer to Sections of this Master Lease. Nothing herein shall be deemed to provide or imply that Lessor is a “merchant” as to any item within the meaning of the UCC as currently in force or as subsequently revised or re-enacted. The terms “herein” or “hereunder” or like terms shall be deemed to refer to this Lease as a whole and not to a particular section. Whenever terms such as “include” or “including” are used in this Lease, they mean “include” or “including”, as the case may be, without limiting the generality of any description or word preceding such term. Whenever the expression “satisfactory to Lessor”, “in Lessor’s judgment” or similar words are used or Lessor is granted the contractual or other right to choose between alternatives or to express its opinion, the satisfaction, judgment, choices and opinions are to be made in Lessor’s sole discretion. The captions or headings in this Lease are made for convenience and general reference only and shall not be construed to describe, define, or limit the scope or intent of the provisions of this Lease. This Lease has been drafted by counsel for Lessor as a convenience to the parties only and shall not, by reason of such action, be construed against Lessor or any other party. Lessee acknowledges and agrees that it has had full opportunity to review this Lease and has had access to counsel of its choice to the extent it deems necessary in order to interpret the legal effect hereof. As used herein, all masculine pronouns shall include the feminine or neuter, and all singular terms the plural form thereof, and vice versa. The exhibits annexed hereto are incorporated herein by this reference and made a part hereof as if contained in the body of this Lease. All references to sections hereunder shall be deemed to refer to sections of this Lease, unless otherwise expressly provided, whether or not “hereof”, “above”, “below” or like words are used.

16.8 Notices. All demands and notices shall be in writing and shall be deemed given when personally delivered or received by facsimile or overnight delivery service, addressed to the other party at the address stated below or at any other address as may be furnished in writing by a party to the other:

If to Lessor to:	Caterpillar Financial Services Corporation
	2120 West End Avenue
	Nashville, TN 37203
	Attn: Credit Manager/Power Finance
	Phone: 615-341-1000
	FAX: 615-341-8581

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	With a Copy to:
	Caterpillar Financial Services Corporation
	2120 West End Avenue
	Nashville, TN 37203
	Attn: Legal Department/Power Finance
	Phone: 615-341-1000
	FAX: 615-341-1083
If to Lessee to:	CDM Resource Management, LLC
	20405 Tomball Pkwy
	Suite 310
	Houston, TX, 77070
	Attn: President
	Phone: 281-376-2980
	FAX: 281-376-0717

16.9 Governing Law. THE PARTIES HERETO HAVE EXPRESSLY AGREED THAT THIS LEASE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT GIVING EFFECT TO THE PRINCIPLES OF CONFLICT OF LAWS THEREOF.

16.10 Jurisdiction. Lessee irrevocably agrees that any legal action or proceeding arising out of or relating to this Lease may be instituted in any federal or state court sitting in the State of New York, subject to Lessor’s sole discretion, and Lessee, in respect of itself and its properties and revenues, irrevocably submit to the jurisdiction of these courts in any such action or proceeding. Lessee waives personal service of process and irrevocably consents to service of process upon it by the mailing of copies thereof by certified or registered mail or courier to Lessee at its address set forth in Section 16.9 hereof. Service shall be deemed to be completed on the tenth Business Day after mailing.

16.11 Waiver of Jury Trial. LESSEE AND LESSOR EACH WAIVES THE RIGHT TO TRIAL BY JURY IN ANY ACTION, SUIT, PROCEEDING OR COUNTERCLAIM OF ANY KIND ARISING OUT OF OR RELATED TO THIS LEASE OR THE OBLIGATIONS HEREUNDER. LESSEE AND LESSOR EACH ACKNOWLEDGES THAT THE FOREGOING WAIVER IS A MATERIAL INDUCEMENT TO THE PARTIES’ ENTERING OF THIS LEASE AND THAT LESSOR AND LESSEE ARE EACH RELYING UPON THE FOREGOING WAIVER IN ITS FUTURE DEALINGS WITH EACH OTHER. LESSEE AND LESSOR EACH WARRANTS AND REPRESENTS THAT IT HAS REVIEWED THE FOREGOING WAIVER WITH ITS LEGAL COUNSEL AND HAS KNOWINGLY AND VOLUNTARILY WAIVED ITS JURY TRIAL RIGHTS FOLLOWING CONSULTATION WITH SUCH LEGAL COUNSEL. IN THE EVENT OF LITIGATION, THE COURT MAY FILE THIS LEASE AS A WRITTEN CONSENT TO A TRIAL.

IN WITNESS WHEREOF, the parties hereto have caused this Lease to be executed by their duly authorized officers as of the day and year first above written.

25

Caterpillar Financial Services Corporation		CDM Resource Management LLC
By:	/s/ James A. Duensing	By: Regency Gas Services, LP, its sole member
Name:	James A. Duensing	By: Regency OLP GP LLC, its general partner
Title:	Executive Vice President and Chief Financial Officer	By:	/s/ Stephen L. Arata
		Name:	Stephen L. Arata
		Title:	Executive Vice President and Chief Financial Officer

26

APPENDIX A

ATTACHED TO AND FORMING PART OF THAT CERTAIN MASTER LEASE AGREEMENT (this “Master Lease”), dated as of February 26, 2009, is between Caterpillar Financial Services Corporation (“Lessor”), a Delaware corporation whose address is 2120 West End Avenue, Nashville, Tennessee 37203, and CDM Resource Management LLC (“Lessee”), a Delaware limited liability company with a principal address of 20405 Tomball Pkwy, Suite 310, Houston, TX, 77070.

The capitalized terms used in this Master Lease and not otherwise defined herein shall have the respective meanings ascribed thereto as follows when used in each of the Lease Documents (such meanings to be equally applicable to both the singular and plural forms of the terms defined), unless the context hereof shall otherwise require:

1. “Abatement” shall have the meaning ascribed thereto in Section 4.4 hereof.

2. “Acceptance Certificate” means a Certificate of Delivery and Acceptance, in the form attached hereto as Exhibit A, that is prepared by Lessor and that is executed by Lessee and identified to the applicable Schedule.

3. “Actions” shall have the meaning ascribed thereto in Section 13.2 hereof.

4. “Applicable Law” means all laws, rules and regulations applicable to the Equipment, Person, conduct, transaction, representation, covenant, agreement or Lease Document in question, including all applicable common law and equitable principles, state and federal constitutions, statutes, rules, regulations and orders of governmental bodies and all judicial orders, judgments and decrees.

5. “Appraisal Process” means the following procedure for determination of the Fair Market Rental Value or the Fair Market Purchase Value (each, hereinafter, the “Fair Market Value”), and the procedure for such determination shall be as follows. If either party gives written notice to the other requesting the determination of the Fair Market Value of the Equipment by an appraisal process, then each party will select an independent appraiser within ten (10) Business Days of receipt of such notice. If either party fails to appoint an appraiser within the required time, the decision of the appraiser appointed by the other party will be final. If two appraisers are appointed, they will confer and agree, within twenty (20) Business Days following the selection of the later of them to be appointed, upon Fair Market Value. If they do not agree within such timeframe, then they must, within five (5) Business Days after their failure to agree, select a third independent appraiser who will independently determine Fair Market Value within twenty (20) Business Days following his/her acceptance of his/her appointment, and such determination will be final. If the initial two appraisers do not agree upon such third appraiser within the prescribed timeframe, then either party may request the American Arbitration Association to appoint such third appraiser within twenty (20) Business Days after such request is made, and both parties will be bound by any appointment so made. Any appraiser appointed pursuant to the foregoing procedure will be instructed to determine, within twenty (20) Business Days after his appointment, Fair Market Value of the Equipment, and his determination thereof will be final. All expenses and costs relating to the Appraisal Procedure will be borne by Lessee.

6. “Attorney’s Fees” means any and all reasonable attorneys’ fees incurred by Lessor (whether by Lessor’s use of in-house counsel or otherwise) related to, arising out of or in any way connected with Lessor’s interests in or defense of any Action or Lessor’s enforcement of its rights and interest with respect to any Equipment or under any Lease, any Lease Document or any other instrument, document or agreement executed in connection with or contemplated by any of the foregoing, which shall include attorneys’ fees incurred by Lessor to collect sums due, during any work-out, with respect to settlement negotiations, to enforce any of its rights or to defend Lessor and which, in any bankruptcy proceeding, shall include any attorneys’ fees incurred in connection with any motion for relief from the automatic stay

1

and any motion to assume or reject any lease, it being the intention of the parties that any and all attorneys’ fees incurred by Lessor in connection with any bankruptcy proceeding shall constitute “actual pecuniary losses” under §365 of the Bankruptcy Code.

7. “Base Term” shall have the meaning ascribed thereto in Section 4.1 hereof.

8. “Base Term Commencement Date” shall mean the date that: (a) Vendor has completed construction of the Equipment; (b) Lessee has inspected it and determined that such Equipment is in the condition required by the Purchase Agreement and is otherwise in good order and condition, and conforms to the specifications, requirements and standards applicable thereto and is satisfactory to Lessee; and (c) all conditions precedent set forth in Section 9 of hereof shall be satisfied. For purposes of this Lease, the foregoing conditions (a) and (b) shall conclusively be deemed to be satisfied upon the latter of the execution of an Acceptance Certificate by Lessee.

9. “Business Day” means any day other than a Saturday, Sunday or other day on which Lessor is not open for the normal conduct of business.

10. “Casualty Occurrence” means any act or occurrence in which any item or component of Equipment is lost, stolen, destroyed, requisitioned, condemned, seized or taken by governmental action or, in Lessor’s opinion, irreparably damaged.

11. “Casualty Value” means, as to any item or component of Equipment and any date of determination, the amount set forth in the Casualty Value Table attached to the applicable Schedule opposite such date.

12. “Dollars” and the sign “$” means lawful money of the United States of America.

13. “Early Buyout Option” means Lessee’s option to purchase the Equipment during the Term in accordance with the terms set forth in Section 5.1 hereof.

14. “Environmental Claim” means any claim, action, cause of action, investigation, prosecution, administrative action or notice (written or oral) by any Person alleging potential liability (including potential liability for investigatory costs, cleanup costs, governmental response costs, natural resources damages, property damages, personal injuries, or penalties) arising out of, based on or resulting from, in part or in whole, (a) the presence, or release into the environment, of any Hazardous Materials at any location, whether or not owned or operated by Lessee, or (b) circumstances forming the basis of any violation, or alleged violation, of the Environmental Laws.

15. “Environmental Laws” means, collectively, any and all applicable local, regional, county, state, federal, national or international law, statute, treaty, directive, decision, judgment, regulation, order, ordinance, permit or similar policy or common law requirement which relate to the protection of human health or the environment relating to the use, refinement, recycling, handling, treatment, storage, disposal, emissions, discharges, releases or threatened releases of Hazardous Materials (including the clean-up of Hazardous Materials in soil, sub-surface strata, surface water or ground water), including the Federal Solid Waste Act as amended by the Resource Conservation and Recovery Act of 1976, 42 U.S.C. §6901, et seq., and the Federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, 42 U.S.C. §7401, et seq., as the same may be amended or modified until the date of closing.

16. “Environmental Losses” means any liabilities, damages, penalties, costs, expenses and losses (including amounts incurred for remedial action, expenses, technical or legal support), whether vested or unvested, fixed or unfixed, actual or potential, and whether with regard to a Governmental Authority, due to an Environmental Claim or action taken to comply with Applicable Law which arise out of the release or disposal of Hazardous Materials into the environment, whether for actions occurring before or after the date hereof, including: (a) the investigation, removal, cleanup, containment or remediation of Hazardous Materials; (b) personal injury, wrongful death or property damage claims; (c) claims for natural resource damages; (d) violation of Environmental Laws; or (e) any Environmental Claim.

2

17. “Equipment” as to each Schedule means the natural gas compression packages and all other property described as the “Equipment” leased on such Schedule, together with all replacements, repairs, additions, attachments, accessories and accessions thereto.

18. “Event of Default” has the meaning set forth in Section 15.1 hereof.

19. “Financial Statements” means all balance sheets, profit and loss statements, statements of income or other financial statements provided by or on behalf of Lessee to Lessor prior to or during the Term hereof, including internally prepared quarterly financial statements and information included in public filings with the U.S Securities and Exchange Commission.

20. “Form Acceptance upon Return” means the acceptance form, substantially in the form of Exhibit B hereto, executed by Lessor and delivered to Lessee indicating Lessor’s approval of the condition of the returned Equipment or any necessary corrections thereto to meet the physical and/or mechanical requirements set forth in Section 5.4 hereof.

21. “GAAP” means U.S. generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board, or in such other statements by such other entity as may be in general use by significant segments of the accounting profession, which are applicable to the circumstances as of the date of determination.

22. “Governmental Authority” means any international or national governmental body, any state, provincial, regional, local, municipal body or agency or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government.

23. “Hazardous Materials” means any and all hazardous materials, toxic substances and pollutants including radioactive substances, hazardous wastes, special wastes, controlled wastes, oils, petroleum and petroleum products, hazardous chemicals, asbestos, polychlorinated biphenyls (PCBs), air pollutants, hazardous air pollutants or and any other materials which may be harmful to human health or the environment and which are now or at any time during the term of this Lease regulated or controlled under Environmental Laws in any of the jurisdictions in which Lessee has operated or is operating.

24. “Improvements” has the meaning set forth in Section 7.2 hereof.

25. “Lease” has the meaning set forth in Section 2 hereof.

26. “Lease Documents” means this Master Lease, the Schedules, the Purchase Agreement and all other agreements, instruments, documents or records executed in connection herewith.

27. “Lessee” has the meaning set forth in the preamble hereof.

28. “Lessor” has the meaning set forth in the preamble hereof, as modified in accordance with the terms hereof.

29. “Lien” means any mortgage, deed of trust, pledge, security interest, hypothecation, assignment, deposit arrangements, encumbrance, lien (statutory or other), privilege, or preference, priority or other security agreement or preferential arrangement, charge or encumbrance of any kind or nature whatsoever (including any conditional sale or other title retention agreement), any financing lease having substantially the same economic effect as any of the foregoing, and the filing of any financing statement or other recordation under the Uniform Commercial Code or comparable law of any jurisdiction to evidence any of the foregoing.

3

30. “Master Lease” has the meaning set forth in the preamble hereof.

31. “Obligations” means individually, collectively and interchangeably, all Rent, Taxes and any and all other liabilities and obligations of Lessee to Lessor of any class or nature, whether arising under or in connection with this Lease, under any other Lease Documents or otherwise, whether now existing or hereafter incurred, direct or indirect, absolute or contingent, secured or unsecured, matured or unmatured, joint or several, whether for rent, principal, interest, fees, expenses, lease obligations, indemnities or otherwise, including future advances of any sort, all future advances made by Lessor for Taxes, insurance and/or repairs to or maintenance of any collateral, the unpaid amount of any Rent hereunder, and any expenses of collection or protection of Lessee’s rights, including Attorneys’ Fees.

32. “Parent” means Regency Energy Partners LP.

33. “Permitted Use Agreement” means a services agreement, sublease or other contractual arrangement pursuant to which Lessee uses the Equipment to provide services to a Permitted User, which such contract must be in form and substance reasonably satisfactory to Lessor and shall, without limitation, satisfy the following conditions: (a) no such Permitted Use Agreement shall negatively affect Lessor’s right, title or interest in the Equipment; (b) the term of each Permitted Use Agreement (including any renewals) shall not extend beyond the Term of the Lease pursuant to which Lessee’s interest in the Equipment arose without prior written consent of Lessor; (c) no interest in the Equipment, except for its use, shall accrue to the Permitted User under the Permitted Use Agreement and no Permitted User shall be granted any purchase options with respect to the Equipment; (d) no Permitted User shall have any right to assign any of its rights or obligations under the Permitted Use Agreement or further sublet the Equipment or provide use thereof to any other Person through a services agreement, sublease or other arrangement; (e) Lessor shall have no obligation or responsibility to any Permitted User to perform under the Permitted Use Agreement; (f) EACH PERMITTED USE AGREEMENT SHALL AT ALL TIMES BE AND SHALL STATE THAT IT IS SUBJECT AND SUBORDINATE TO THIS LEASE, AND THE RIGHTS OF EACH PERMITTED USER UNDER EACH PERMITTED USE AGREEMENT SHALL AT ALL TIMES BE SUBJECT AND SUBORDINATE TO LESSOR’S RIGHTS UNDER THIS LEASE AND IN THE EQUIPMENT; (g) UPON THE OCCURRENCE OF A DEFAULT UNDER THIS LEASE, LESSOR SHALL BE ENTITLED TO ENTER UPON THE PROPERTY AND REMOVE THE EQUIPMENT FROM THE PROPERTY, WITHOUT LIABILITY TO LESSEE OR ANY PERMITTED USER AND NO SUCH PERSONS WILL ASSERT ANY SET-OFF, DEFENSE, COUNTER-CLAIM OR CROSS COMPLAINT AGAINST LESSOR’S INTEREST IN THE EQUIPMENT; (h) each Permitted Use Agreement is and shall continue to be in compliance with all Applicable Laws and governmental regulations; and (i) the Equipment shall remain personal property regardless of its use or manner of attachment to the Property.

34. “Permitted User” means a Person to whom Lessee furnishes the Equipment solely pursuant to Permitted Use Agreements.

35. “Permits and Related Rights” All city, county, state, federal, governmental or other permits, authorizations, tags, licenses, certificates and any other documents, instruments, agreements or rights necessary or desirable in order to use and operate the Equipment, including environmental and operating permits, licenses and other rights.

36. “Person” means an individual, partnership, limited liability company, corporation, trust or unincorporated organization, and Governmental Authority.

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37. “Property” means the (a) real property on which the Equipment is located including all rights granted to Lessee by the landowner or adjoining landowners or under a Permitted Use Agreement to access said real property whether by fee interest, right of way, license, contract, easement, or otherwise and (b) the pipeline or other property to which the Equipment is attached, but so much of the pipeline as is necessary to accomplish the purposes hereunder.

38. “Purchase Agreement” means one or more purchase orders or written agreements pursuant to which Vendor has agreed to sell the equipment described therein to Lessor for lease pursuant to the terms of this Lease, including, without limitation any such purchase or written agreement whereby Vendor agrees to purchase components, assemble and package the equipment to be sold by Vendor thereunder.

39. “Purchase Option” means Lessee’s option to purchase the Equipment in accordance with the terms set forth in Section 5.2 hereof.

40. “Renewal Option” means Lessee’s option to renew the Term in accordance with the terms set forth in Section 5.3 hereof.

41. “Renewal Term” shall mean have the meaning ascribed thereto in Section 5.3(a) thereof.

42. “Rent” means quarterly rent in arrears for the use of the Equipment.

43. “Schedule” has the meaning set forth in Section 2 hereof.

44. “Taxes” means any and all present or future sales, use, personal property, excise, gross receipts, franchise, stamp or other taxes, levies, imposts, duties, fees, assessments, deductions, withholdings, turnover taxes, value added taxes or other charges of whatsoever nature that may now or hereafter be imposed or asserted by any ”Governmental Authority or any taxing authority therein and all interest, penalties or similar liabilities with respect thereto, taxes of any nature, together with any penalties, fines or additions to tax and interest thereon; provided, however, that the term Taxes shall not include franchise taxes or any taxes imposed by the United States of America or any state or political subdivision thereof that are imposed on or measured by the net income of Lessor (as opposed to gross receipts).

45. “Term” means the term of this Lease as set forth in Section 4.1 plus any Renewal Term arising under the terms of Section 5.3 and any automatic extension of a Term arising under the provisions of this Master Lease.

46. “UCC” means the Uniform Commercial Code as in effect from time to time in the applicable jurisdiction.

47. “Vendor” means the manufacturer, packager, seller, or supplier of the Equipment pursuant to a Purchase Agreement, which such party shall be identified on the applicable Schedule.

Caterpillar Financial Services Corporation		CDM Resource Management LLC
By:	/s/ James A. Duensing	By: Regency Gas Services, LP, its sole member
Name:	James A. Duensing	By: Regency OLP GP LLC, its general partner
Title:	Executive Vice President and Chief Financial Officer	By:	/s/ Stephen L. Arata
		Name:	Stephen L. Arata
		Title:	Executive Vice President and Chief Financial Officer

5

EX-10.22

Exhibit 10.22

Execution Copy

$45,000,000

REVOLVING CREDIT AGREEMENT

dated as of February 26, 2009

among

REGENCY ENERGY PARTNERS LP

as Borrower,

and

THE GUARANTORS PARTY HERETO,

as Guarantors,

THE LENDERS PARTY HERETO,

and

GENERAL ELECTRIC CAPITAL CORPORATION,

as Administrative Agent

TABLE OF CONTENTS

Section		Page
Article I DEFINITIONS
Section 1.01	Defined Terms	1
Section 1.02	Terms Generally	16
Section 1.03	Accounting Terms; GAAP	16
Section 1.04	Resolution of Drafting Ambiguities	16
Article II THE CREDITS
Section 2.01	Commitments	17
Section 2.02	Loans	17
Section 2.03	Borrowing Procedure	18
Section 2.04	Evidence of Debt; Repayment of Loans	19
Section 2.05	Fees	19
Section 2.06	Interest on Loans	20
Section 2.07	Termination and Reduction of Commitments	20
Section 2.08	Interest Elections	21
Section 2.09	Optional and Mandatory Prepayments of Loans	22
Section 2.10	Alternate Rate of Interest	23
Section 2.11	Yield Protection	23
Section 2.12	Breakage Payments	24
Section 2.13	Payments Generally; Pro Rata Treatment; Sharing of Setoffs	25
Section 2.14	Taxes	26
Section 2.15	Mitigation Obligations; Replacement of Lenders	28
Article III REPRESENTATIONS AND WARRANTIES
Section 3.01	Organization; Powers	29
Section 3.02	Authorization; Enforceability	29
Section 3.03	No Conflicts	30
Section 3.04	Financial Statements	30
Section 3.05	Properties	30
Section 3.06	Intellectual Property	30
Section 3.07	Subsidiaries	31
Section 3.08	Litigation; Compliance with Laws	31
Section 3.09	Agreements	31
Section 3.10	Federal Reserve Regulations	31
Section 3.11	Investment Company Act	31

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Section		Page
Section 3.12	Use of Proceeds	31
Section 3.13	Taxes	32
Section 3.14	No Material Misstatements	32
Section 3.15	Labor Matters	32
Section 3.16	Solvency	32
Section 3.17	Employee Benefit Plans	33
Section 3.18	Real Property	33
Section 3.19	Insurance	33
Section 3.20	Anti-Terrorism Law	33
Article IV CONDITIONS PRECEDENT
Section 4.01	Conditions to the Initial Loans	34
Section 4.02	Conditions to All Loans	35
Article V COVENANTS
Section 5.01	Indenture Covenants	35
Section 5.02	Amended Credit Agreement Covenants	36
Section 5.03	Financial Information; Compliance	36
Section 5.04	Litigation and Other Notices	36
Section 5.05	Access to Properties and Inspections	36
Section 5.06	Use of Proceeds	37
Section 5.07	Additional Guarantors	37
Section 5.08	Further Assurances	37
Section 5.09	Notice of Effectiveness of Amendment Agreement	37
Section 5.10	Anti-Terrorism Law; Anti-Money Laundering	37
Section 5.11	Embargoed Person	38
Article VI GUARANTEE
Section 6.01	The Guarantee	38
Section 6.02	Obligations Unconditional	39
Section 6.03	Reinstatement	40
Section 6.04	Subrogation; Subordination	40
Section 6.05	Remedies	40
Section 6.06	Instrument for the Payment of Money	40
Section 6.07	Continuing Guarantee	41
Section 6.08	General Limitation on Guarantee Obligations	41
Section 6.09	Release of Guarantors	41

-ii-

Section		Page
Article VII EVENTS OF DEFAULT
Section 7.01	Events of Default	41
Section 7.02	Rescission	43
Article VIII THE ADMINISTRATIVE AGENT
Section 8.01	Appointment and Authority	44
Section 8.02	Rights as a Lender	44
Section 8.03	Exculpatory Provisions	44
Section 8.04	Reliance by Administrative Agent	45
Section 8.05	Delegation of Duties	45
Section 8.06	Resignation of Administrative Agent	46
Section 8.07	Non-Reliance on Administrative Agent and Other Lenders	46
Article IX MISCELLANEOUS
Section 9.01	Notices	47
Section 9.02	Waivers; Amendment	49
Section 9.03	Expenses; Indemnity; Damage Waiver	51
Section 9.04	Successors and Assigns	53
Section 9.05	Survival of Agreement	55
Section 9.06	Counterparts; Integration; Effectiveness; Electronic Execution	55
Section 9.07	Severability	56
Section 9.08	Right of Setoff	56
Section 9.09	Governing Law; Jurisdiction; Consent to Service of Process	56
Section 9.10	Waiver of Jury Trial	57
Section 9.11	Headings	57
Section 9.12	Treatment of Certain Information; Confidentiality	57
Section 9.13	USA PATRIOT Act Notice	58
Section 9.14	Interest Rate Limitation	58
Section 9.15	Obligations Absolute	59

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SCHEDULES
Schedule 1.01(a)	Guarantors
Schedule 3.07(a)	Subsidiaries and Organizational Chart

EXHIBITS
Exhibit A	Form of Administrative Questionnaire
Exhibit B	Form of Assignment and Assumption
Exhibit C	Form of Borrowing Request
Exhibit D	Form of Interest Election Request
Exhibit E	Form of Joinder Agreement
Exhibit F	Form of Closing Checklist
Exhibit G	Form of Note
Exhibit H	Form of Non-Bank Certificate

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REVOLVING CREDIT AGREEMENT

This REVOLVING CREDIT AGREEMENT (this “Agreement”) dated as of February 26, 2009, among REGENCY ENERGY PARTNERS LP, a Delaware limited partnership (including any successor-in-interest, “Borrower”), the Guarantors (such term and each other capitalized term used but not defined where used having the meaning given to it in Section 1.01), the Lenders, and GENERAL ELECTRIC CAPITAL CORPORATION, as administrative agent (in such capacity, the “Administrative Agent”) for the Lenders.

WITNESSETH:

WHEREAS, the Borrower has requested and the Lenders have agreed to make available to the Borrower a revolving credit facility upon and subject to the terms and conditions set forth herein to fund the Pre-Closing Expenditures.

NOW, THEREFORE, the parties hereto hereby agree that in consideration of the mutual agreements, provisions and covenants contained herein as follows:

ARTICLE I

DEFINITIONS

SECTION 1.01 Defined Terms. As used in this Agreement, the following terms shall have the meanings specified below:

“ABR”, when used in reference to any Loan, is used when such Loan is bearing interest at a rate determined by reference to the Alternate Base Rate.

“Adjusted LIBO Rate” shall mean, with respect to any Eurodollar Loan for any Interest Period, (a) an interest rate per annum (rounded upward, if necessary, to the nearest 1/100th of 1%) determined by the Administrative Agent to be equal to the LIBO Rate for such Eurodollar Loan in effect for such Interest Period divided by (b) 1 minus the Statutory Reserves (if any) for such Eurodollar Loan for such Interest Period.

“Administrative Agent” shall have the meaning assigned to such term in the preamble hereto and includes each other person appointed as the successor pursuant to Article VIII.

“Administrative Questionnaire” shall mean an Administrative Questionnaire in substantially the form of Exhibit A.

“Affiliate” shall mean, when used with respect to a specified person, another person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the person specified.

“Agent Fees” shall have the meaning assigned to such term in Section 2.05(b).

“Agreement” shall have the meaning assigned to such term in the preamble hereto.

“Alternate Base Rate” shall mean, for any day, a rate per annum (rounded upward, if necessary, to the nearest 1/100th of 1%) equal to the greater of (a) the Federal Funds Effective Rate in effect on such day plus 0.50% and (b) the Adjusted LIBO Rate for a borrowing with a one-month Interest Period plus 1.50% .. If the Administrative Agent shall have determined (which determination shall be conclusive absent manifest error) that it is unable to ascertain the (i) Federal Funds Effective Rate or (ii) the Adjusted LIBO Rate, in each case, for any reason, including the inability or failure of the Administrative Agent to obtain sufficient quotations in accordance with the terms of the definition thereof, the Alternate Base Rate shall be determined without regard to (x) clause (b) of the preceding sentence in the case of clause (i) in this sentence and (y) clause (c) of the preceding sentence in the case of clause (ii) in this sentence, in each case, until the circumstances giving rise to such inability no longer exist. Any change in the Alternate Base Rate due to a change in the Federal Funds Effective Rate or the Adjusted LIBO Rate shall be effective on the effective date of such change in the Federal Funds Effective Rate or the Adjusted LIBO Rate, respectively.

“Amended Credit Agreement” shall mean that certain Fourth Amended and Restated Credit Agreement dated as of August 15, 2006, as amended by a first amendment dated as of June 15, 2007, as further amended by a second amendment dated as of June 29, 2007, as further amended by a third amendment dated as of September 28, 2007, as further amended by a fourth amendment dated as of January 15, 2008, as further amended by a fifth amendment dated as of February 13, 2008 and as further amended by a sixth amendment and waiver dated as of May 9, 2008, by and among Regency Gas Services, Borrower, the guarantors party thereto, Wachovia Bank, National Association, as administrative agent, collateral agent, swingline lender and issuing bank and the lenders and other parties thereto.

“Amendment Agreement” shall mean that certain Amendment No. 7 to the Amended Credit Agreement, dated as of the Effective Date, among Regency Gas Services, Wachovia Bank, National Association, as administrative agent, and the lenders party thereto.

“Amendment Effective Date” shall mean the date upon which the conditions to effectiveness of the Amendment Agreement set forth in Section 2 thereof are satisfied or waived in accordance with the terms thereof.

“Anti-Terrorism Laws” shall have the meaning assigned to such term in Section 3.20.

“Applicable Margin” shall mean: (a) with respect to an ABR Loan (i) from the Effective Date to the last day of the third calendar month immediately thereafter, three percent (3.00%) per annum and (ii) from the first day of the fourth calendar month immediately following the Effective Date, ten percent (10.00%) per annum; and (b) with respect to a Eurodollar Loan (i) from the Effective Date to the last day of the third calendar month immediately thereafter, four percent (4.00%) per annum and (ii) from the first day of the fourth calendar month immediately following the Effective Date, eleven percent (11.00%) per annum.

“Approved Fund” shall mean any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

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“Assignment and Assumption” shall mean an assignment and assumption entered into by a Lender and an Eligible Assignee (with the consent of any party whose consent is required by Section 9.04(b)), and accepted by the Administrative Agent, in substantially the form of Exhibit B, or any other form approved by the Administrative Agent.

“Board” shall mean the Board of Governors of the Federal Reserve System of the United States.

“Board of Directors” shall mean, with respect to any person, (i) in the case of any corporation, the board of directors of such person, (ii) in the case of any limited liability company, the board of managers (or equivalent) of such person, (iii) in the case of any partnership, the Board of Directors (or equivalent) of the general partner of such person and (iv) in any other case, the functional equivalent of the foregoing.

“Borrower” shall have the meaning assigned to such term in the preamble hereto.

“Borrowing Request” shall mean a request by Borrower in accordance with the terms of Section 2.03 and substantially in the form of Exhibit C, or such other form as shall be approved by the Administrative Agent.

“Business Day” shall mean any day other than a Saturday, Sunday or other day on which banks in New York City are authorized or required by law to close; provided, however, that when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

“Capital Lease Obligations” of any person shall mean the obligations of such person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

A “Change in Control” shall be deemed to have occurred if (a) Borrower at any time ceases to own, directly or indirectly, 100% of the Equity Interests of Regency Gas Services; (b) (i) the Permitted Holders cease to own, or to have the power to vote or direct the voting of, Voting Stock of the Ultimate General Partner representing a majority of the voting power of the total outstanding Voting Stock of the Ultimate General Partner or (ii) the Permitted Holders cease to own Equity Interests representing a majority of the total economic interests of the Equity Interests of the Ultimate General Partner; or (c) the Ultimate General Partner shall cease to exercise Control over Borrower.

For purposes of this definition, a person shall not be deemed to have beneficial ownership of Equity Interests subject to a stock purchase agreement, merger agreement or similar agreement, including an agreement relating to a sale of Voting Stock or Equity Interests of the Ultimate General Partner, until the consummation of the transactions contemplated by such agreement.

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“Change in Law” shall mean the occurrence, after the Effective Date (or with respect to any Lender, if later, the date on which such Lender becomes a Lender, except to the extent that such change was considered a Change in Law with respect to such Lender’s assignor immediately prior to such Lender becoming a Lender), of any of the following: (a) the adoption or taking into effect of any law, treaty, order, policy, rule or regulation, (b) any change in any law, treaty, order, policy, rule or regulation or in the administration, interpretation or application thereof by any Governmental Authority or (c) the making or issuance of any request, guideline or directive (whether or not having the force of law) by any Governmental Authority.

“Charges” shall have the meaning assigned to such term in Section 9.14.

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Commitment” shall mean (i) with respect to each Lender on the Effective Date, the commitment of such Lender to make Loans pursuant to Section 2.01 and (ii) the commitment of each person after the Effective Date to make Loans pursuant to an Assignment and Assumption, in each case as the same may be or (x) reduced from time to time pursuant to Section 2.07, (y) reduced or increased from time to time pursuant to assignments to or by such Lender pursuant to Section 9.04. The aggregate principal amount of the Commitments on the Effective Date is $45.0 million.

“Commitment Fee” shall have the meaning assigned to such term in Section 2.05(a).

“Communications” shall have the meaning assigned to such term in Section 9.01(d).

“Companies” shall mean Borrower and its Subsidiaries; and “Company” shall mean any one of them.

“Contingent Obligation” shall mean, as to any person, any obligation, agreement or arrangement of such person guaranteeing or intended to guarantee any Indebtedness, leases, dividends or other obligations (“primary obligations”) of any other person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of such person, whether or not contingent, (a) to purchase any such primary obligation or any property constituting direct or indirect security therefor; (b) to advance or supply funds (i) for the purchase or payment of any such primary obligation or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor; (c) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation; (d) with respect to bankers’ acceptances, letters of credit and similar credit arrangements, until a reimbursement obligation arises (which reimbursement obligation shall constitute Indebtedness); or (e) otherwise to assure or hold harmless the holder of such primary obligation against loss in respect thereof; provided, however, that the term “Contingent Obligation” shall not include endorsements of instruments for deposit or collection in the ordinary course of business or any product warranties. The amount of any Contingent Obligation shall be deemed to be an amount equal to the stated or determinable amount of the primary obligation in respect of which such Contingent Obligation is made (or, if less, the maximum amount of such primary obligation for which such person may be liable, whether

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singly or jointly, pursuant to the terms of the instrument evidencing such Contingent Obligation) or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof (assuming such person is required to perform thereunder) as determined by such person in good faith.

“Control” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a person, whether through the ownership of voting securities, by contract or otherwise, and the terms “Controlling” and “Controlled” shall have meanings correlative thereto.

“Default” shall mean any event, occurrence or condition which is, or upon notice, lapse of time or both would constitute, an Event of Default.

“Default Rate” shall have the meaning assigned to such term in Section 2.06(c).

“dollars” or “$” shall mean lawful money of the United States.

“Effective Date” shall mean February 26, 2009.

“Eligible Assignee” shall mean (a) any Lender, (b) an Affiliate of any Lender, (c) an Approved Fund of a Lender and (d) any other person approved by the Administrative Agent and Borrower (each such approval not to be unreasonably withheld or delayed); provided that (x) no approval of Borrower shall be required during the continuance of an Event of Default and (y) “Eligible Assignee” shall not include Borrower or any of its Affiliates or Subsidiaries or any natural person.

“Embargoed Person” shall have the meaning assigned to such term in Section 5.11.

“Environment” shall mean ambient air, surface water and groundwater (including potable water, navigable water and wetlands), the land surface or subsurface strata, natural resources, the workplace or as otherwise defined in any Environmental Law.

“Environmental Claim” shall mean any claim, notice, demand, order, action, suit, proceeding or other communication alleging liability for investigation, remediation, removal, cleanup, response, corrective action, damages to natural resources, personal injury, property damage, fines, penalties or other costs resulting from, related to or arising out of (i) the presence, Release or threatened Release in or into the Environment of Hazardous Material at any location or (ii) any violation of Environmental Law, and shall include any claim seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from, related to or arising out of the presence, Release or threatened Release of Hazardous Material or alleged injury or threat of injury to health, safety or the Environment.

“Environmental Law” shall mean any and all applicable present and future treaties, laws, statutes, ordinances, regulations, rules, decrees, orders, judgments, consent orders, consent decrees, code or other binding requirements, and the common law, relating to protection of public health or the Environment, the Release or threatened Release of Hazardous Material, natural resources or natural resource damages, or occupational safety or health.

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“Equity Interest” shall mean, with respect to any person, any and all shares, interests, participations or other equivalents, including membership interests (however designated, whether voting or nonvoting), of equity of such person, including, if such person is a partnership, partnership interests (whether general or limited) and any other interest or participation that confers on a person the right to receive a share of the profits and losses of, or distributions of property of, such partnership, whether outstanding on the Effective Date or issued after the Effective Date, but excluding debt securities convertible or exchangeable into such equity.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as the same may be amended from time to time.

“ERISA Affiliate” shall mean, with respect to any person, any trade or business (whether or not incorporated) that, together with such person, is treated as a single employer under Section 414 of the Code.

“ERISA Event” shall mean (a) any “reportable event,” as defined in Section 4043 of ERISA or the regulations issued thereunder, with respect to a Plan (other than an event for which the 30-day notice period is waived by regulation); (b) the existence with respect to any Plan of an “accumulated funding deficiency” (as defined in Section 412 of the Code or Section 302 of ERISA), whether or not waived; (c) the failure to make by its due date a required installment under Section 412(m) of the Code with respect to any Plan or the failure to make any required contribution to a Multiemployer Plan; (d) the filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; (e) the incurrence by any Company or any of its ERISA Affiliates of any liability under Title IV of ERISA with respect to the termination of any Plan; (f) the receipt by any Company or any of its ERISA Affiliates from the PBGC or a plan administrator of any notice relating to the intention to terminate any Plan or Plans or to appoint a trustee to administer any Plan, or the occurrence of any event or condition which could reasonably be expected to constitute grounds under ERISA for the termination of, or the appointment of a trustee to administer, any Plan; (g) the incurrence by any Company or any of its ERISA Affiliates of any liability with respect to the withdrawal from any Plan or Multiemployer Plan; (h) the receipt by any Company or its ERISA Affiliates of any notice, concerning the imposition of Withdrawal Liability or a determination that a Multiemployer Plan is, or is expected to be, insolvent or in reorganization, within the meaning of Title IV of ERISA; (i) the “substantial cessation of operations” within the meaning of Section 4062(e) of ERISA with respect to a Plan; (j) the making of any amendment to any Plan which could result in the imposition of a lien or the posting of a bond or other security; and (k) the occurrence of a nonexempt prohibited transaction (within the meaning of Section 4975 of the Code or Section 406 of ERISA) which could reasonably be expected to result in liability to any Company.

“Eurodollar Loan” shall mean any Loan bearing interest at a rate determined by reference to the Adjusted LIBO Rate in accordance with the provisions of Article II.

“Event of Default” shall have the meaning assigned to such term in Section 7.01.

“Excluded Taxes” shall mean, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of Borrower

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hereunder, (a) taxes imposed on or measured by its overall net income (however denominated), franchise taxes imposed on it (in lieu of net income taxes) and branch profits taxes imposed on it, by a jurisdiction (or any political subdivision thereof) as a result of the recipient being organized or having its principal office or, in the case of any Lender, having its applicable lending office or doing or having done business (other than a business deemed to arise by virtue of the transactions contemplated by this Agreement) in such jurisdiction and (b) in the case of a Foreign Lender (other than an assignee pursuant to a request by Borrower under Section 2.15), any U.S. federal withholding tax that (i) is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party hereto (or designates a new lending office), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from Borrower with respect to such withholding tax pursuant to Section 2.14(a); provided that this subclause (b)(i) shall not apply to any Tax imposed on a Lender in connection with an interest or participation in any Loan or other obligation that such Lender was required to acquire pursuant to Section 2.13(c), or (ii) is attributable to such Foreign Lender’s failure to comply with Section 2.14(e).

“Executive Order” shall have the meaning assigned to such term in Section 3.20.

“Federal Funds Effective Rate” shall mean, for any day, the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System of the United States arranged by federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for the day for such transactions received by the Administrative Agent from three federal funds brokers of recognized standing selected by it.

“Fee Letter” shall mean the confidential Fee Letter, dated February 26, 2009, among Borrower and the Administrative Agent.

“Fees” shall mean the Commitment Fees and the Agent Fees.

“Foreign Lender” shall mean any Lender that is not, for United States federal income tax purposes, (i) an individual who is a citizen or resident of the United States, (ii) a corporation, partnership or other entity treated as a corporation or partnership created or organized in or under the laws of the United States, or any political subdivision thereof, (iii) an estate whose income is subject to U.S. federal income taxation regardless of its source or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of such trust and one or more United States persons have the authority to control all substantial decisions of such trust.

“Foreign Subsidiary” shall mean a Subsidiary that is organized under the laws of a jurisdiction other than the United States or any state thereof or the District of Columbia.

“Fund” shall mean any person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

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“GAAP” shall mean generally accepted accounting principles in the United States applied on a consistent basis.

“General Partner” shall mean Regency GP LP, a Delaware limited partnership and the general partner of Borrower.

“Governmental Authority” shall mean the government of the United States of America or any other nation, or of any political subdivision thereof, whether state, provincial or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).

“Guaranteed Obligations” shall have the meaning assigned to such term in Section 6.01.

“Guarantees” shall mean the guarantees issued pursuant to Article VI by the Guarantors.

“Guarantors” shall mean each Subsidiary listed on Schedule 1.01(a) and each other Subsidiary that is or becomes a party to this Agreement pursuant to Section 5.07.

“Haynesville Project” shall mean the planned midstream infrastructure development in the Haynesville Shale region of northwestern Louisiana by the RIGS Holdings Joint Venture.

“Hazardous Materials” shall mean the following: hazardous substances; hazardous wastes; polychlorinated biphenyls (“PCBs”) or any substance or compound containing PCBs; asbestos or any asbestos-containing materials in any form or condition; radon or any other radioactive materials including any source, special nuclear or by-product material; petroleum, crude oil or any fraction thereof; and any other pollutant or contaminant or chemicals, wastes, materials, compounds, constituents or substances, subject to regulation or which can give rise to liability under any Environmental Laws.

“Hedging Agreement” shall mean any swap, cap, collar, forward purchase or similar agreements or arrangements dealing with interest rates, currency exchange rates or commodity prices, either generally or under specific contingencies.

“Hedging Obligations” shall mean obligations under or with respect to Hedging Agreements.

“Indebtedness” of any person shall mean, without duplication, (a) all obligations of such person for borrowed money; (b) all obligations of such person evidenced by bonds, debentures, notes or similar instruments; (c) all obligations of such person under conditional sale or other title retention agreements relating to property purchased by such person; (d) all obligations of such person issued or assumed as the deferred purchase price of property or services (excluding trade accounts payable and accrued obligations incurred in the ordinary course of business and not overdue by more than 90 days); (e) all Indebtedness of others secured by any Lien on property owned or acquired by such person, whether or not the obligations secured thereby have been assumed, but limited to the fair market value of such property; (f) all Capital Lease

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Obligations, Purchase Money Obligations and synthetic lease obligations of such person; (g) all Hedging Obligations to the extent required to be reflected on a balance sheet of such person; (h) all Sale/Leaseback Attributable Indebtedness of such person; (i) all obligations of such person for the reimbursement of any obligor in respect of letters of credit, letters of guaranty, bankers’ acceptances and similar credit transactions; and (j) all Contingent Obligations of such person in respect of Indebtedness referred to in clauses (a) through (i) above. The Indebtedness of any person shall include the Indebtedness of any other entity (including any partnership in which such person is a general partner) to the extent such person is liable therefor as a result of such person’s ownership interest in or other relationship with such entity, except (other than in the case of general partner liability) to the extent that terms of such Indebtedness expressly provide that such person is not liable therefor. Notwithstanding the foregoing, Indebtedness shall not include (A) deferred compensation arrangements, (B) earn-out obligations or purchase price adjustments until matured or earned or (C) non-compete or consulting obligations incurred in connection with Permitted Acquisitions.

“Indenture” shall mean that certain Indenture, dated as of December 12, 2006 among Borrower, Regency Energy Finance Corp., a Delaware corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee.

“Indemnified Taxes” shall mean all Taxes other than Excluded Taxes.

“Indemnitee” shall have the meaning assigned to such term in Section 9.03(b).

“Information” shall have the meaning assigned to such term in Section 9.12.

“Intellectual Property” shall have the meaning assigned to such term in Section 3.06.

“Interest Election Request” shall mean a request by Borrower to convert or continue a Loan in accordance with Section 2.08(b), substantially in the form of Exhibit D.

“Interest Payment Date” shall mean (a) with respect to any ABR Loan, the last Business Day of each March, June, September and December to occur during any period in which such Loan is outstanding, (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Loan and, in the case of a Eurodollar Loan with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period and (c) with respect to any Loan, the Maturity Date or such earlier date on which the Commitments are terminated.

“Interest Period” shall mean, with respect to any Eurodollar Loan, the period commencing on the date of such Loan and ending on the numerically corresponding day in the calendar month that is one, two, three or six months (or, if each affected Lender so agrees, nine or twelve months) thereafter, as Borrower may elect; provided that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day, and (b) any Interest Period that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of

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such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Loan initially shall be the date on which such Loan is made and thereafter shall be the effective date of the most recent conversion or continuation of such Loan.

“Investment Agreement” shall mean that certain contribution agreement to be entered into by and among Regency HIG, General Electric Capital Corporation, Alinda Gas Pipeline I, L.P. and Alinda Gas Pipeline II, L.P. relating to the RIGS Holding Joint Venture.

“Joinder Agreement” shall mean a joinder agreement substantially in the form of Exhibit E.

“Joint Venture” shall mean (i) a joint venture with a third party so long as such entity would not constitute a Subsidiary, (ii) a Subsidiary formed with the intention of establishing a joint venture; provided that if such entity still constitutes a Subsidiary ninety days after formation it shall no longer constitute a Joint Venture, or (iii) notwithstanding anything to the contrary herein, each of Edwards Lime Gathering LLC and (except as otherwise expressly set forth herein) the RIGS Holdings Joint Venture, for so long as any portion of the ownership interests therein are owned by a Person that is not a Loan Party or an Affiliate of any Loan Party.

“Lenders” shall mean (i) on the Effective Date, (a) each lender signatory hereto and (ii) after the Effective Date, any financial institution that becomes a party hereto pursuant to an Assignment and Assumption, other than, in each case, any such financial institution that ceases to be a party hereto pursuant to an Assignment and Assumption.

“LIBO Rate” shall mean, with respect to any Eurodollar Loan for any Interest Period, the rate per annum determined by the Administrative Agent to be the arithmetic mean (rounded upward, if necessary, to the nearest 1/100th of 1%) of the offered rates for deposits in dollars with a term comparable to such Interest Period that appears on the Telerate British Bankers Assoc. Interest Settlement Rates Page (as defined below) at approximately 11:00 a.m., London, England time, on the second full Business Day preceding the first day of such Interest Period; provided, however, that (i) if no comparable term for an Interest Period is available, the LIBO Rate shall be determined using the weighted average of the offered rates for the two terms most nearly corresponding to such Interest Period and (ii) if there shall at any time no longer exist a Telerate British Bankers Assoc. Interest Settlement Rates Page, “LIBO Rate” shall mean, with respect to each day during each Interest Period pertaining to Eurodollar Loans, the rate per annum equal to the rate at which the Administrative Agent is offered deposits in dollars at approximately 11:00 a.m., London, England time, two Business Days prior to the first day of such Interest Period in the London interbank market for delivery on the first day of such Interest Period for the number of days comprised therein and in an amount comparable to its portion of the amount of such Eurodollar Loan to be outstanding during such Interest Period; provided, further, that in no event shall the LIBO Rate be less than three percent (3.00%) per annum. “Telerate British Bankers Assoc. Interest Settlement Rates Page” shall mean the display designated as Page 3750 on the Telerate System Incorporated Service (or such other page as may replace such page on such service for the purpose of displaying the rates at which dollar deposits are offered by leading banks in the London interbank deposit market).

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“Lien” shall mean, with respect to any property, (a) any mortgage, deed of trust, lien, pledge, claim, charge, assignment, hypothecation, security interest or encumbrance of any kind or any arrangement to provide priority or preference or any filing of any financing statement under the UCC or any other similar notice of lien under any similar notice or recording statute of any Governmental Authority, including any easement, right-of-way or other encumbrance on title to Real Property or Pipelines in each of the foregoing cases whether voluntary or imposed by law, and any agreement to give any of the foregoing; (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such property; and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities.

“Loan” shall mean a loan made by the Lenders to Borrower pursuant to Section 2.01. Each Loan shall either be an ABR Loan or a Eurodollar Loan.

“Loan Documents” shall mean this Agreement, the Notes (if any) and, solely for purposes of paragraph (e) of Section 7.01, the Fee Letter.

“Loan Parties” shall mean Borrower and the Guarantors.

“Margin Stock” shall have the meaning assigned to such term in Regulation U.

“Material Adverse Effect” shall mean (a) a material adverse effect on the business, property, results of operations or condition, financial or otherwise, of Borrower and its Subsidiaries, taken as a whole; (b) material impairment of the ability of the Loan Parties to fully and timely perform any of their material obligations under any Loan Document; or (c) material impairment of the rights of or benefits or remedies, taken as a whole, available to the Lenders under any Loan Document.

“Maturity Date” shall mean the date that is the earlier of (i) the date that is three months after the Final Maturity Date (as such term is defined in the Amended Credit Agreement) and (ii) November 15, 2011, or if such date is not a Business Day, the first Business Day thereafter.

“Maximum Rate” shall have the meaning assigned to such term in Section 9.14.

“Multiemployer Plan” shall mean a multiemployer plan within the meaning of Section 4001(a)(3) or Section 3(37) of ERISA (a) to which any Company or any ERISA Affiliate is then making or accruing an obligation to make contributions; (b) to which any Company or any ERISA Affiliate has within the preceding five plan years made contributions; or (c) with respect to which any Company could incur liability.

“Notes” shall mean any notes evidencing the Loans issued pursuant to this Agreement, if any, substantially in the form of Exhibit G.

“Obligations” shall mean (a) obligations of Borrower and the other Loan Parties from time to time arising under or in respect of the due and punctual payment of (i) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed

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or allowable in such proceeding) on the Loans, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise and (ii) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of Borrower and the other Loan Parties under this Agreement and the other Loan Documents and (b) the due and punctual performance of all covenants, agreements, obligations and liabilities of Borrower and the other Loan Parties under or pursuant to this Agreement and the other Loan Documents.

“OFAC” shall have the meaning assigned to such term in Section 3.20.

“Organizational Documents” shall mean, with respect to any person, (i) in the case of any corporation, the certificate of incorporation and by-laws (or similar documents) of such person, (ii) in the case of any limited liability company, the certificate of formation and operating agreement (or similar documents) of such person, (iii) in the case of any limited partnership, the certificate of formation and limited partnership agreement (or similar documents) of such person, (iv) in the case of any general partnership, the partnership agreement (or similar document) of such person and (v) in any other case, the functional equivalent of the foregoing.

“Other Taxes” shall mean all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or under any other Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.

“Participant” shall have the meaning assigned to such term in Section 9.04(d).

“PBGC” shall mean the Pension Benefit Guaranty Corporation referred to and defined in ERISA.

“Permitted Acquisitions” shall have the meaning assigned to such term in the Amended Credit Agreement.

“Permitted Holders” shall mean (a) Regency GP Acquirer LP and (b) any other Affiliate of General Electric Company.

“Permitted Liens” shall have the meaning assigned to such term in the Amended Credit Agreement.

“person” shall mean any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“Pipeline” shall mean gathering systems and pipelines, together with all contracts, rights-of-way, easements, servitudes, fixtures, equipment, improvements, permits, records, and other real property appertaining thereto.

“Plan” shall mean any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 302 of ERISA which is maintained or contributed to by any Company or its ERISA Affiliate or with respect to which any Company could incur liability (including under Section 4069 of ERISA).

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“Platform” shall have the meaning assigned to such term in Section 9.01(d).

“Pre-Closing Expenditures” shall mean the amount of all reasonable out-of-pocket third party invoiced expenditures actually paid in connection with the development and construction of the Haynesville Project by RIGS and its Affiliates from the Effective Date to but not including the earlier of (i) the Amendment Effective Date and (ii) April 30, 2009.

“property” shall mean any right, title or interest in or to property or assets of any kind whatsoever, whether real, personal or mixed and whether tangible or intangible and including Equity Interests or other ownership interests of any person and whether now in existence or owned or hereafter entered into or acquired, including all Real Property or Pipelines.

“Purchase Money Obligation” shall mean, for any person, the obligations of such person in respect of Indebtedness (including Capital Lease Obligations) incurred for the purpose of financing all or any part of the purchase price of any property (including Equity Interests of any person) or the cost of installation, construction or improvement of any property and any refinancing thereof; provided, however, that (i) such Indebtedness is incurred prior to, contemporaneously with or within one year after such acquisition of such property by such person and (ii) the amount of such Indebtedness does not exceed 100% of the cost of such acquisition, installation, construction or improvement, as the case may be, including related costs, fees and expenses.

“Real Property” shall mean, collectively, all right, title and interest (including any leasehold, mineral or other estate) in and to any and all parcels of or interests in real property owned, leased or operated by any person, whether by lease, license or other means, together with, in each case, all easements, hereditaments and appurtenances relating thereto, all improvements and appurtenant fixtures and equipment, all general intangibles and contract rights and other property and rights incidental to the ownership, lease or operation thereof.

“Regency Gas Services” shall mean Regency Gas Services LP, a Delaware limited partnership.

“Regency Haynesville” shall mean a direct or indirect Subsidiary of Regency Gas Services formed for the sole purpose of directly holding all direct or indirect ownership interests of Regency Gas Services in the RIGS Holdings Joint Venture.

“Regency HIG” shall mean Regency Haynesville Intrastate Gas LLC, a Delaware limited liability company.

“Register” shall have the meaning assigned to such term in Section 9.04(c).

“Regulation D” shall mean Regulation D of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

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“Regulation T” shall mean Regulation T of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Related Parties” shall mean, with respect to any person, such person’s Affiliates and the partners, directors, officers, employees, agents and advisors of such person and of such person’s Affiliates.

“Release” shall mean any spilling, leaking, seepage, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, disposing, depositing, dispersing, emanating or migrating of any Hazardous Material in, into, onto or through the Environment.

“Required Lenders” shall mean Lenders having more than 50% of all Commitments.

“Requirements of Law” shall mean, collectively, any and all requirements of any Governmental Authority including any and all laws, judgments, orders, decrees, ordinances, rules, regulations, statutes or case law.

“RIGS” shall mean Regency Intrastate Gas LLC, a Delaware limited liability company.

“RIGS Assets” shall mean all Equity Interests issued, and all assets owned, by RIGS.

“RIGS Holdings Joint Venture” shall mean an entity formed by Regency Haynesville for the purpose of such entity becoming a joint venture with a third party, owning all of the RIGS Assets and participating in the Haynesville Project. RIGS Holdings Joint Venture shall, except as expressly set forth herein, be treated for all purposes as a “Joint Venture” hereunder.

“RIGS JV Documents” shall mean (i) the Investment Agreement and (ii) all other material agreements and definitive documentation relating to the RIGS Holding Joint Venture, including the shareholders or limited liability company agreement relating thereto and the management services agreement relating thereto.

“Sale and Leaseback Transaction” shall have the meaning assigned to such term in the Amended Credit Agreement.

“Sale/Leaseback Attributable Indebtedness” shall mean, when used with respect to any Sale and Leaseback Transaction, as at the time of determination, the present value (discounted at a rate equivalent to Borrower’s then-current weighted average cost of funds for borrowed money as at the time of determination, compounded on a semi-annual basis) of the total obligations of the lessee for rental payments during the remaining term of the lease included in any such Sale and Leaseback Transaction.

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“Statutory Reserves” shall mean, for any Interest Period for any Eurodollar Loan, the average maximum rate at which reserves (including any marginal, supplemental or emergency reserves) are required to be maintained during such Interest Period under Regulation D by member banks of the United States Federal Reserve System in New York City with deposits exceeding one billion dollars against “Eurocurrency liabilities” (as such term is used in Regulation D). Eurodollar Loans shall be deemed to constitute Eurodollar liabilities and to be subject to such reserve requirements without benefit of or credit for proration, exceptions or offsets which may be available from time to time to any Lender under Regulation D.

“Subsidiary” shall mean, with respect to any person (the “parent”) at any date, (i) any person the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, (ii) any other corporation, limited liability company, association or other business entity of which securities or other ownership interests representing more than 50% of the voting power of all Equity Interests entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors thereof are, as of such date, owned, controlled or held by the parent and/or one or more subsidiaries of the parent, (iii) any partnership (a) the sole general partner or the managing general partner of which is the parent and/or one or more subsidiaries of the parent or (b) the only general partners of which are the parent and/or one or more subsidiaries of the parent and (iv) any other person that is otherwise Controlled by the parent and/or one or more subsidiaries of the parent. Unless the context requires otherwise, “Subsidiary” refers to a Subsidiary of Borrower. Notwithstanding any of the foregoing, neither Edwards Lime Gathering LLC nor the RIGS Holdings Joint Venture shall be a Subsidiary for so long as it is a Joint Venture (except, with respect to the RIGS Holdings Joint Venture, as shall be otherwise expressly set forth herein).

“Tax Return” shall mean all returns, statements, filings, attachments and other documents or certifications required to be filed in respect of Taxes.

“Taxes” shall mean all present or future taxes, levies, imposts, duties, deductions, withholdings, assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Transferred Guarantor” shall have the meaning assigned to such term in Section 6.09.

“Type,” when used in reference to any Loan, refers to whether the rate of interest on such Loan is determined by reference to the Adjusted LIBO Rate or the Alternate Base Rate.

“UCC” shall mean the Uniform Commercial Code as in effect from time to time (except as otherwise specified) in any applicable state or jurisdiction.

“Ultimate General Partner” shall mean Regency GP LLC, a Delaware limited liability company and the general partner of the General Partner.

“United States” shall mean the United States of America.

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“Voting Stock” shall mean, with respect to any person, any class or classes of Equity Interests pursuant to which the holders thereof have the general voting power under ordinary circumstances to vote in the election of the Board of Directors of such person.

“Withdrawal Liability” shall mean liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA.

SECTION 1.02 Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” The word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the context requires otherwise (a) any definition of or reference to any Loan Document, agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any person shall be construed to include such person’s successors and assigns, (c) the words “herein,” “hereof” and “hereunder,” and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (d) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement, (e) any reference to any law or regulation herein shall refer to such law or regulation as amended, modified or supplemented from time to time and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

SECTION 1.03 Accounting Terms; GAAP. Except as otherwise expressly provided herein, all financial statements to be delivered pursuant to this Agreement shall be prepared in accordance with GAAP as in effect from time to time and all terms of an accounting or financial nature shall be construed and interpreted in accordance with GAAP, as in effect on the Effective Date unless otherwise agreed to by Borrower and the Required Lenders. If GAAP shall change after the date hereof, the parties hereto agree to negotiate in good faith to modify the covenants herein so that they may be construed and interpreted in accordance with GAAP as then in effect.

SECTION 1.04 Resolution of Drafting Ambiguities. Each Loan Party acknowledges and agrees that it was represented by counsel in connection with the execution and delivery of the Loan Documents to which it is a party, that it and its counsel reviewed and participated in the preparation and negotiation hereof and thereof and that any rule of construction to the effect that ambiguities are to be resolved against the drafting party shall not be employed in the interpretation hereof or thereof.

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ARTICLE II

THE CREDITS

SECTION 2.01 Commitments. Subject to the terms and conditions and relying upon the representations and warranties herein set forth, each Lender agrees, severally and not jointly to make Loans to Borrower, from time to time on any Business Day from and including the Effective Date to the earlier of (i) April 30, 2009 and (ii) termination of the Commitments in accordance with the terms hereof, in an aggregate principal amount at any time outstanding not exceeding such Lender’s Commitment. Within the limits set forth in the immediately preceding sentence and subject to the terms, conditions and limitations set forth herein, Borrower may borrow, pay or prepay and reborrow Loans.

SECTION 2.02 Loans.

(a) Each Loan shall be made by the Lenders ratably in accordance with their applicable Commitments; provided that the failure of any Lender to make its Loan shall not in itself relieve any other Lender of its obligation to lend hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to make any Loan required to be made by such other Lender). ABR Loans shall be in an aggregate principal amount that is (i) an integral multiple of $100,000 and not less than $1.0 million or (ii) equal to the remaining available balance of the applicable Commitments. Eurodollar Loans shall be in an aggregate principal amount that is (i) an integral multiple of $100,000 and not less than $3.0 million or (ii) equal to the remaining available balance of the applicable Commitments.

(b) Subject to Sections 2.10 and 2.11, each Loan shall be either an ABR Loan or Eurodollar Loan as Borrower may request pursuant to Section 2.03. Each Lender may at its option make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of Borrower to repay such Loan in accordance with the terms of this Agreement. Loans of more than one Type may be outstanding at the same time; provided that Borrower shall not be entitled to request any Loan that, if made, would result in more than seven Eurodollar Loans outstanding hereunder at any one time. For purposes of the foregoing, Loans having different Interest Periods, regardless of whether they commence on the same date, shall be considered separate Loans.

(c) Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds to such account in New York City as the Administrative Agent may designate not later than 11:00 a.m., New York City time, and the Administrative Agent shall promptly credit the amounts so received to an account as directed by Borrower in the applicable Borrowing Request maintained with the Administrative Agent or, if a Loan shall not be made on such date because any condition precedent herein specified shall not have been met, return the amounts so received to the respective Lenders.

(d) Unless the Administrative Agent shall have received notice from a Lender prior to the date of any Loan that such Lender will not make available to the Administrative Agent such Lender’s portion of such Loan, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Loan in

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accordance with paragraph (c) above, and the Administrative Agent may, in reliance upon such assumption, make available to Borrower on such date a corresponding amount. If the Administrative Agent shall have so made funds available, then, to the extent that such Lender shall not have made such portion available to the Administrative Agent, each of such Lender and Borrower severally agrees to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to Borrower until the date such amount is repaid to the Administrative Agent at (i) in the case of Borrower, the interest rate applicable at the time to the Loans and (ii) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount shall constitute such Lender’s Loan for purposes of this Agreement, and Borrower’s obligation to repay the Administrative Agent such corresponding amount pursuant to this Section 2.02(d) shall cease.

(e) Notwithstanding any other provision of this Agreement, Borrower shall not be entitled to request, or to elect to convert or continue, any Loan if the Interest Period requested with respect thereto would end after the Maturity Date.

SECTION 2.03 Borrowing Procedure. To request a Loan, Borrower shall deliver, by hand delivery or telecopier, a duly completed and executed Borrowing Request to the Administrative Agent (i) in the case of a Eurodollar Loan, not later than 11:00 a.m., New York City time, three Business Days before the date of the proposed Loan or (ii) in the case of an ABR Loan, (A) equal to or less than $5.0M, not later than 9:00 a.m., New York City time, on the date of the proposed Loan and (B) in excess of $5.0M, not later than 9:00 a.m., New York City time, one Business Day before the date of the proposed Loan. Each Borrowing Request shall be irrevocable and shall specify the following information in compliance with Section 2.02:

(a) the aggregate amount of such Loan;

(b) the date of such Loan, which shall be a Business Day;

(c) whether such Loan is to be an ABR Loan or of Eurodollar Loan;

(d) in the case of a Eurodollar Loan, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period”;

(e) the location and number of Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.02(c); and

(f) that the conditions set forth in Sections 4.02(b)-(c) have been satisfied as of the date of the notice.

If no election as to the Type of Loan is specified, then the requested Loan shall be an ABR Loan. If no Interest Period is specified with respect to any requested Eurodollar Loans, then Borrower shall be deemed to have selected an Interest Period of one month’s duration. Promptly following receipt of a Borrowing Request in accordance with this Section, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part thereof.

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SECTION 2.04 Evidence of Debt; Repayment of Loans.

(a) Promise to Repay. Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender, the then unpaid principal amount of each Loan of such Lender on the Maturity Date.

(b) Lender and Administrative Agent Records. Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement. The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Loan made hereunder, the Type thereof and the Interest Period applicable thereto; (ii) the amount of any principal or interest due and payable or to become due and payable from Borrower to each Lender hereunder; and (iii) the amount of any sum received by the Administrative Agent hereunder for the account of the Lenders and each Lender’s share thereof. The entries made in the accounts maintained pursuant to this paragraph shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of Borrower to repay the Loans in accordance with their terms.

(c) Promissory Notes. Any Lender by written notice to Borrower (with a copy to the Administrative Agent) may request that Loans made by it be evidenced by a promissory note. In such event, Borrower shall prepare, execute and deliver to such Lender a promissory note payable to the order of such Lender (or, if requested by such Lender, to such Lender and its registered assigns) in the form of Exhibit G. Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to Section 9.04) be represented by one or more promissory notes in such form payable to the order of the payee named therein (or, if such promissory note is a registered note, to such payee and its registered assigns).

SECTION 2.05 Fees.

(a) Commitment Fee. Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee (a “Commitment Fee”) equal to 0.75% per annum on the average daily unused amount of the Commitment of such Lender during the period from and including the Effective Date to but excluding the date on which such Commitment terminates. Accrued Commitment Fees shall be payable in arrears (A) on the last Business Day of March, June, September and December of each year, commencing on the first such date to occur after the Effective Date, and (B) on the date on which such Commitment terminates. Commitment Fees shall be computed on the basis of a year of 360 days and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

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(b) Agent Fees. Borrower agrees to pay to the Administrative Agent, for its own account, the fees set forth in the Fee Letter and/or such other fees payable in the amounts and at the times separately agreed upon between Borrower and the Administrative Agent (the “Agent Fees”).

(c) All Fees shall be paid on the dates due, in immediately available funds, to the Administrative Agent for distribution, if and as appropriate, among the Lenders. Once paid, none of the Fees shall be refundable under any circumstances.

SECTION 2.06 Interest on Loans.

(a) ABR Loans. Subject to the provisions of Section 2.06(c), ABR Loans shall bear interest at a rate per annum equal to the Alternate Base Rate plus the Applicable Margin in effect from time to time.

(b) Eurodollar Loans. Subject to the provisions of Section 2.06(c), Eurodollar Loans shall bear interest at a rate per annum equal to the Adjusted LIBO Rate for the Interest Period in effect for such Loan plus the Applicable Margin in effect from time to time.

(c) Default Rate. Notwithstanding the foregoing, during the continuance of an Event of Default, all overdue Obligations shall, to the extent permitted by applicable law, bear interest, after as well as before judgment, at a per annum rate equal to (i) in the case of principal of or interest on any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section 2.06 or (ii) in the case of any other amount, 2% plus the rate otherwise applicable to such amount (in either case, the “Default Rate”).

(d) Interest Payment Dates. Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan; provided that (i) interest accrued pursuant to Section 2.06(c) shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan, accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e) Interest Calculation. All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate or Adjusted LIBO Rate shall be determined by the Administrative Agent in accordance with the provisions of this Agreement and such determination shall be conclusive absent manifest error.

SECTION 2.07 Termination and Reduction of Commitments.

(a) Termination of Commitments. Unless otherwise terminated earlier pursuant to the terms hereof, the Commitments shall automatically terminate on the earlier of (i) the Amendment Effective Date and (ii) April 30, 2009.

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(b) Optional Terminations and Reductions. At its option, Borrower may at any time terminate, or from time to time permanently reduce, the Commitments; provided that each reduction of the Commitments shall be in an amount that is an integral multiple of $500,000 and not less than $1.0 million.

(c) Borrower Notice. Borrower shall notify the Administrative Agent in writing of any election to terminate or reduce the Commitments under Section 2.07(b) at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by Borrower pursuant to this Section shall be irrevocable; provided that a notice of termination of the Commitments delivered by Borrower may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be revoked by Borrower (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied. Any termination or reduction of the Commitments shall be permanent. Each reduction of the Commitments shall be made ratably among the Lenders in accordance with their respective Commitments.

SECTION 2.08 Interest Elections.

(a) Generally. Each Loan initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Loan, shall have an initial Interest Period as specified in such Borrowing Request. Thereafter, Borrower may elect to convert such Loan to a different Type or to continue such Loan and, in the case of a Eurodollar Loan, may elect Interest Periods therefor, all as provided in this Section. Any Loan (or, if outstanding Loans are being combined, any group of Loans having the same proposed Interest Period) to be made or continued as, or converted into, Eurodollar Loans shall be in an amount that is an integral multiple of $500,000 and not less than $5.0 million. Notwithstanding anything to the contrary, Borrower shall not be entitled to request any conversion or continuation that, if made, would result in more than seven Eurodollar Loans outstanding hereunder at any one time.

(b) Interest Election Notice. To make an election pursuant to this Section, Borrower shall deliver, by hand delivery or telecopier, a duly completed and executed Interest Election Request to the Administrative Agent not later than the time that a Borrowing Request would be required under Section 2.03 if Borrower were requesting a Loan of the Type resulting from such election to be made on the effective date of such election. Each Interest Election Request shall be irrevocable. Each Interest Election Request shall specify the following information in compliance with Section 2.02:

(i) the Loan to which such Interest Election Request applies, or if outstanding Loans are being combined, allocation to each resulting Loan (in which case the information to be specified pursuant to clauses (iii) and (iv) below shall be specified for each resulting Loan);

(ii) the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

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(iii) whether the resulting Loan is to be an ABR Loan or a Eurodollar Loan; and

(iv) if the resulting Loan is a Eurodollar Loan, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

If any such Interest Election Request requests a Eurodollar Loan but does not specify an Interest Period, then Borrower shall be deemed to have selected an Interest Period of one month’s duration.

Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Loan.

(c) Automatic Conversion to ABR Loan. If an Interest Election Request with respect to a Eurodollar Loan is not timely delivered prior to the end of the Interest Period applicable thereto, then, unless such Loan is repaid as provided herein, at the end of such Interest Period such Loan shall be converted to an ABR Loan. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing, the Administrative Agent or the Required Lenders may require, by notice to Borrower, that (i) no outstanding Loan may be converted to or continued as a Eurodollar Loan and (ii) unless repaid, each Eurodollar Loan shall be converted to an ABR Loan at the end of the Interest Period applicable thereto.

SECTION 2.09 Optional and Mandatory Prepayments of Loans.

(a) Optional Prepayments. Borrower shall have the right at any time and from time to time to prepay any Loan, in whole or in part, subject to the requirements of this Section 2.09; provided that each partial prepayment shall be in an amount that is an integral multiple of $500,000 and not less than $1.0 million.

(b) Mandatory Prepayments. Upon the occurrence of the Amendment Effective Date, Borrower shall, on such date, repay or prepay all its outstanding Loans.

(c) Notice of Prepayment. Borrower shall notify the Administrative Agent by written notice of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Loan, not later than 11:00 a.m., New York City time, three Business Days before the date of prepayment and (ii) in the case of prepayment of an ABR Loan, not later than four hours (during the normal Business Day) prior to such prepayment; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of the Commitments as contemplated by Section 2.07, then such notice of prepayment may be revoked if such termination is revoked in accordance with Section 2.07. Each such notice shall specify the prepayment date, the principal amount of each Loan or portion thereof to be prepaid. Promptly following receipt of any such notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each partial prepayment of any Loan shall be in an amount that would be permitted in the case of a Loan of the same Type as provided in Section 2.02, except as necessary to apply fully the required amount of a mandatory prepayment.

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SECTION 2.10 Alternate Rate of Interest. If prior to the commencement of any Interest Period for a Eurodollar Loan:

(a) the Administrative Agent determines (which determination shall be final and conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate for such Interest Period; or

(b) the Administrative Agent is advised in writing by the Required Lenders that the Adjusted LIBO Rate for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Loan for such Interest Period;

then the Administrative Agent shall give written notice thereof to Borrower and the Lenders as promptly as practicable thereafter and, until the Administrative Agent notifies Borrower and the Lenders that the circumstances giving rise to such notice no longer exist (which notice shall be promptly given), (i) any Interest Election Request that requests the conversion of any Loan to, or continuation of any Loan as, a Eurodollar Loan shall be ineffective and (ii) if any Borrowing Request requests a Eurodollar Loan, such Loan shall be made as an ABR Loan.

SECTION 2.11 Yield Protection.

(a) Increased Costs Generally. If any Change in Law shall:

(i) impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in, by any Lender (except any reserve requirement reflected in the Adjusted LIBO Rate);

(ii) subject any Lender to any tax of any kind whatsoever with respect to this Agreement, or any Loan made by it, or change the basis of taxation of payments to such Lender in respect thereof (except for Indemnified Taxes or Other Taxes covered by Section 2.14 and the imposition of, or any change in the rate of, any Excluded Tax payable by such Lender); or

(iii) impose on any Lender or the London interbank market any other condition, cost or expense (excluding Taxes) affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan), or to increase the cost to such Lender or such Lender’s holding company, if any, or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or any other amount), then, upon request of such Lender, Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b) Capital Requirements. If any Lender determines (in good faith, but in its sole absolute discretion) that any Change in Law affecting such Lender or any lending office of

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such Lender or such Lender’s holding company, if any, regarding capital requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Loans made by such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy), then from time to time Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c) Certificates for Reimbursement. A certificate of a Lender setting forth in reasonable detail the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section 2.11 and delivered to Borrower shall be conclusive absent manifest error. Subject to Section 2.11(d), Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

(d) Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to this Section 2.11 shall not constitute a waiver of such Lender’s right to demand such compensation; provided that Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than six months prior to the date that such Lender notifies Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the six-month period referred to above shall be extended to include the period of retroactive effect thereof) .

SECTION 2.12 Breakage Payments. In the event of (a) the payment or prepayment, whether optional or mandatory, of any principal of any Eurodollar Loan earlier than the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan earlier than the last day of the Interest Period applicable thereto, (c) the failure to borrow, convert, continue or prepay any Loan on the date specified in any notice delivered pursuant hereto or (d) the assignment of any Eurodollar Loan earlier than the last day of the Interest Period applicable thereto as a result of a request by Borrower pursuant to Section 2.15(b), then, in any such event, Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the Eurodollar market. A certificate of any Lender setting forth in reasonable detail any amount or amounts that such Lender is entitled to receive pursuant to this Section 2.12 shall be delivered to Borrower (with a

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copy to the Administrative Agent) and shall be conclusive and binding absent manifest error. Borrower shall pay such Lender the amount shown as due on any such certificate within 5 days after receipt thereof.

SECTION 2.13 Payments Generally; Pro Rata Treatment; Sharing of Setoffs.

(a) Payments Generally. Borrower shall make each payment required to be made by it hereunder or under any other Loan Document (whether of principal, interest, fees or of amounts payable under Section 2.11, 2.12, 2.14 or 9.03, or otherwise) on or before the time expressly required hereunder or under such other Loan Document for such payment (or, if no such time is expressly required, prior to 2:00 p.m., New York City time), on the date when due, in immediately available funds, without setoff, deduction or counterclaim. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices at the address specified in Section 9.01(a)(ii) hereof, except that payments pursuant to Sections 2.11, 2.12, 2.14 and 9.03 shall be made directly to the persons entitled thereto and payments pursuant to other Loan Documents shall be made to the persons specified therein. The Administrative Agent shall distribute any such payments received by it for the account of any other person to the appropriate recipient promptly following receipt thereof. If any payment under any Loan Document shall be due on a day that is not a Business Day, unless specified otherwise, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments under each Loan Document shall be made in dollars, except as expressly specified otherwise.

(b) Insufficient Funds. If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, interest and fees then due hereunder, such funds shall be applied (i) first, toward payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, toward payment of principal then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal then due to such parties.

(c) Sharing of Setoff. If any Lender shall, by exercising any right of setoff or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans or other Obligations resulting in such Lender’s receiving payment of a proportion of the aggregate amount of its Loans and accrued interest thereon or other Obligations greater than its pro rata share thereof as provided herein, then the Lender receiving such greater proportion shall (a) notify the Administrative Agent of such fact, and (b) purchase (for cash at face value) participations in the Loans and such other obligations of the other Lenders, or make such other adjustments as shall be equitable, so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and other amounts owing them, provided that:

(i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest; and

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(ii) the provisions of this paragraph shall not be construed to apply to (x) any payment made by Borrower pursuant to and in accordance with the express terms of this Agreement or (y) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to Borrower or any Subsidiary thereof (as to which the provisions of this paragraph shall apply).

Each Loan Party consents to the foregoing and agrees, to the extent it may effectively do so under applicable Requirements of Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against such Loan Party rights of setoff and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of such Loan Party in the amount of such participation.

(d) Borrower Default. Unless the Administrative Agent shall have received notice from Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders hereunder that Borrower will not make such payment, the Administrative Agent may assume that Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due. In such event, if Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

(e) Lender Default. If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.02(c), 2.13(d) or 9.03(c), then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid.

SECTION 2.14 Taxes.

(a) Payments Free of Taxes. Any and all payments by or on account of any obligation of Borrower hereunder or under any other Loan Document shall be made free and clear of and without reduction or withholding for any Indemnified Taxes or Other Taxes; provided that if Borrower shall be required by applicable Requirements of Law to deduct any Indemnified Taxes (including any Other Taxes) from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent or Lender, as the case may be, receives an amount equal to the sum it would have received had no such deductions been made, (ii) Borrower shall make such deductions and (iii) Borrower shall timely pay the full amount deducted to the relevant Governmental Authority in accordance with applicable Requirements of Law.

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(b) Payment of Other Taxes by Borrower. Without limiting the provisions of paragraph (a) above, Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable Requirements of Law.

(c) Indemnification by Borrower. Borrower shall indemnify the Administrative Agent and each Lender, within 20 days after demand therefor, for the full amount of any Indemnified Taxes or Other Taxes (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) paid by the Administrative Agent or such Lender, as the case may be, and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(d) Evidence of Payments. As soon as practicable after any payment of Indemnified Taxes or Other Taxes by Borrower to a Governmental Authority, Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Status of Lenders. Any Foreign Lender shall, to the extent it may lawfully do so, deliver to Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the request of Borrower or the Administrative Agent or if the Lender’s factual or legal circumstances have changed since it last provided the form, rendering such form obsolete or incorrect, but only if such Foreign Lender is legally entitled to do so), whichever of the following is applicable:

(i) duly completed copies of Internal Revenue Service Form W-8BEN claiming eligibility for benefits of an income tax treaty to which the United States of America is a party,

(ii) duly completed copies of Internal Revenue Service Form W-8ECI,

(iii) in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate, in substantially the form of Exhibit H, or any other form approved by the Administrative Agent, to the effect that such Foreign Lender is not (A) a “bank” within the meaning of Section 881(c)(3)(A) of the Code, (B) a “10 percent shareholder” of Borrower within the meaning of Section 881(c)(3)(B) of the Code, or (C) a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code and (y) duly completed copies of Internal Revenue Service Form W-8BEN, or

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(iv) any other form prescribed by applicable Requirements of Law as a basis for claiming exemption from or a reduction in United States Federal withholding tax duly completed together with such supplementary documentation as may be prescribed by applicable Requirements of Law to permit Borrower to determine the withholding or deduction required to be made.

(f) Treatment of Certain Refunds. If the Administrative Agent or a Lender determines, in its good faith sole discretion, that it has received a refund of any Indemnified Taxes or Other Taxes as to which it has been indemnified by Borrower or with respect to which Borrower has paid additional amounts pursuant to this Section, it shall pay to Borrower an amount equal to such refund (but only to the extent of indemnity payments made, or additional amounts paid, by Borrower under this Section with respect to the Indemnified Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses of the Administrative Agent, or such Lender, as the case may be, and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund) so as to leave such Lender or Administrative Agent in no better or worse position than in which each would have been if payment of the relevant additional amount had not been made; provided that Borrower, upon the request of the Administrative Agent or such Lender, agrees to repay the amount paid over to Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent or such Lender in the event the Administrative Agent or such Lender is required to repay such refund to such Governmental Authority. This paragraph shall not be construed to require the Administrative Agent or any Lender to make available its tax returns (or any other information relating to its taxes that it deems confidential) to Borrower or any other person.

SECTION 2.15 Mitigation Obligations; Replacement of Lenders.

(a) Designation of a Different Lending Office. If any Lender requests compensation under Section 2.11, or requires Borrower to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.11 or 2.14, as the case may be and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment. A certificate setting forth such costs and expenses submitted by such Lender to Borrower shall be conclusive absent manifest error.

(b) Replacement of Lenders. If any Lender requests compensation under Section 2.11, or if Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, or if any Lender defaults in its obligation to fund Loans hereunder, or if Borrower exercises its replacement rights under Section 9.02(c), then Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required

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by, Section 9.04), all of its interests, rights and obligations under this Agreement and the other Loan Documents to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that:

(i) Borrower shall have paid to the Administrative Agent the processing and recordation fee specified in Section 9.04(b);

(ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Loans, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 2.12), from the assignee (to the extent of such outstanding principal and accrued interest and fees) or Borrower (in the case of all other amounts);

(iii) in the case of any such assignment resulting from a claim for compensation under Section 2.11 or payments required to be made pursuant to Section 2.14, such assignment will result in a reduction in such compensation or payments thereafter; and

(iv) such assignment does not conflict with applicable Requirements of Law.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling Borrower to require such assignment and delegation cease to apply.

ARTICLE III

REPRESENTATIONS AND WARRANTIES

Each Loan Party represents and warrants to the Administrative Agent and each of the Lenders that:

SECTION 3.01 Organization; Powers. Each Loan Party (a) is duly organized and validly existing under the laws of the jurisdiction of its organization, (b) has all requisite organizational power and authority to carry on its business as now conducted and to own and lease its property and (c) is qualified and in good standing (to the extent such concept is applicable in the applicable jurisdiction) to do business in every jurisdiction where such qualification is required, except in such jurisdictions where the failure to so qualify or be in good standing, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect. There is no existing default under any Organizational Document of any Loan Party or any event which, with the giving of notice or passage of time or both, would constitute a default by any party thereunder.

SECTION 3.02 Authorization; Enforceability. The Loan Documents to be entered into by each Loan Party are within such Loan Party’s powers and have been duly authorized by all necessary action on the part of such Loan Party. This Agreement has been duly executed and delivered by each Loan Party and constitutes, and each other Loan Document to which any Loan Party is to be a party, when executed and delivered by such Loan Party, will constitute, a legal, valid and binding obligation of such Loan Party, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

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SECTION 3.03 No Conflicts. The execution, delivery and performance by each Loan Party of each Loan Document to which it is a party (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority, except (i) such as have been obtained or made and are in full force and effect, and (ii) consents, approvals, registrations, filings, permits or actions the failure to obtain or perform which could not reasonably be expected to result in a Material Adverse Effect, (b) will not violate the Organizational Documents of any Loan Party, (c) will not violate any Requirement of Law in any material respect, (d) will not violate or result in a default or require any consent or approval under any indenture, agreement or other instrument binding upon any Loan Party or its property, or give rise to a right thereunder to require any payment to be made by any Loan Party, except for violations, defaults or the creation of such rights that could not reasonably be expected to result in a Material Adverse Effect, and (e) will not result in the creation or imposition of any Lien on any property of any Loan Party.

SECTION 3.04 Financial Statements.

(a) Historical Financial Statements. Borrower has heretofore delivered to the Administrative Agent the consolidated balance sheets and related income statements and statements of cash flows and statements of changes in member interests of Borrower (i) as of and for the 12-month period ended December 31, 2008, and (ii) monthly financial statements for each fiscal month ended thereafter ending more than 45 days prior to the Effective Date, and in the case of clause (i), certified by the chief financial officer of Borrower. Such financial statements have been prepared in accordance with GAAP and fairly present, in all material respects, the consolidated financial condition and results of operations and cash flows of Borrower and its Subsidiaries as of the dates and for the periods to which they relate.

(b) No Liabilities. Except as set forth in the financial statements referred to in Section 3.04(a), there are no liabilities of the Borrower and its Subsidiaries of any kind, whether accrued, contingent, absolute, determined, determinable or otherwise, which could reasonably be expected to result in a Material Adverse Effect. Since December 31, 2008 there has been no event, change, circumstance or occurrence that, individually or in the aggregate, has had or could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.05 Properties. The Borrower has good title to, or valid leasehold interests in, all its property material to its business, free and clear of all Liens except for, Permitted Liens and minor irregularities or deficiencies in title that, individually or in the aggregate, do not materially interfere with its ability to conduct its business as currently conducted or to utilize such property for its intended purpose. The property of the Borrower and its Subsidiaries, taken as a whole, is in good operating order, condition and repair (ordinary wear and tear excepted) in accordance with industry standards.

SECTION 3.06 Intellectual Property. The Borrower owns, or is licensed to use, all patents, patent applications, trademarks, trade names, servicemarks, copyrights, technology, trade secrets, proprietary information, domain names, know-how and processes necessary for the

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conduct of its business as currently conducted (the “Intellectual Property”), except for those the failure to own or license which, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect. No claim has been asserted and is pending by any person challenging or questioning the use of any such Intellectual Property or the validity or effectiveness of any such Intellectual Property, nor does any Loan Party know of any valid basis for any such claim, in each case that could reasonably be expected to result in a Material Adverse Effect. The use of such Intellectual Property by each Loan Party does not infringe the rights of any person, except for such claims and infringements that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

SECTION 3.07 Subsidiaries. Schedule 3.07(a) sets forth a list of (i) all the Subsidiaries of Borrower and their jurisdictions of organization as of the Effective Date and (ii) an accurate organizational chart, showing the ownership structure of Borrower and each of its Subsidiaries on the Effective Date.

SECTION 3.08 Litigation; Compliance with Laws. There are no actions, suits or proceedings at law or in equity by or before any Governmental Authority now pending or, to the knowledge of any Loan Party, threatened against or affecting any Loan Party or any business, property or rights of any Loan Party (a) that involve any Loan Document or (b) which could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect. The Borrower is not in violation of, nor will the continued operation of its property as currently conducted violate or result in default of any Requirement of Law, where such violation or default, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.09 Agreements. The Borrower is not a party to any agreement or instrument or subject to any corporate or other constitutional restriction that has resulted or could reasonably be expected to result in a Material Adverse Effect. The Borrower is not in default in any manner under any provision of any indenture or other agreement or instrument evidencing Indebtedness, or any other agreement or instrument to which it is a party or by which it or any of its property is or may be bound, where such default could reasonably be expected to result in a Material Adverse Effect, and no condition exists which, with the giving of notice or the lapse of time or both, would constitute such a default.

SECTION 3.10 Federal Reserve Regulations. No Loan Party is engaged principally, or as one of its important activities, in the business of extending credit for the purpose of buying or carrying Margin Stock. No part of the proceeds of any Loan will be used, whether directly or indirectly, and whether immediately, incidentally or ultimately, for any purpose that entails a violation of, or that is inconsistent with, the provisions of the regulations of the Board, including Regulation T, U or X.

SECTION 3.11 Investment Company Act. No Loan Party is an “investment company” or a company “controlled” by an “investment company,” as defined in, or subject to regulation under, the Investment Company Act of 1940, as amended.

SECTION 3.12 Use of Proceeds. The Borrower will use the proceeds of the Loans to fund the Pre-Closing Expenditures.

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SECTION 3.13 Taxes. The Borrower has (a) timely filed or caused to be timely filed all federal Tax Returns and all material state, local and foreign Tax Returns or materials required to have been filed by it and (b) duly and timely paid, collected or remitted or caused to be duly and timely paid, collected or remitted all Taxes (whether or not shown on any Tax Return) due and payable, collectible or remittable by it and all assessments received by it, except Taxes (i) that are being contested in good faith by appropriate proceedings and for which the Borrower has set aside on its books adequate reserves in accordance with GAAP and (ii) which could not, individually or in the aggregate, have a Material Adverse Effect. The Borrower has made adequate provision in accordance with GAAP for all Taxes not yet due and payable. The Borrower is unaware of any proposed or pending tax assessments, deficiencies or audits that could be reasonably expected to, individually or in the aggregate, result in a Material Adverse Effect.

SECTION 3.14 No Material Misstatements. No written information, report, financial statement, certificate, Borrowing Request, exhibit or schedule furnished by or on behalf of any Loan Party to the Administrative Agent or any Lender in connection with the negotiation of any Loan Document or included therein or delivered pursuant thereto, taken as a whole, contained or contains any material misstatement of fact or omitted or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were or are made, not misleading as of the date such information is dated or certified; provided that (a) to the extent any such information, report, financial statement, exhibit or schedule was based upon or constitutes a forecast or projection, each Loan Party represents only that it acted in good faith and utilized reasonable assumptions and due care in the preparation of such information, report, financial statement, exhibit or schedule (it being recognized by the Lenders, however, that projections as to future events are not to be viewed as facts and that results during the period(s) covered by such projections may differ from the projected results and that such differences may be material and that the Loan Parties make no representation that such projections will be realized) and (b) as to statements, information and reports supplied by third parties after the Effective Date, Borrower represents only that it is not aware of any material misstatement or omission therein.

SECTION 3.15 Labor Matters. As of the Effective Date, there are no strikes, lockouts or slowdowns against the Borrower pending or, to the knowledge of the Borrower, threatened. The hours worked by and payments made to employees of the Borrower have not been in violation of the Fair Labor Standards Act of 1938, as amended, or any other applicable federal, state, local or foreign law dealing with such matters in any manner which could reasonably be expected to result in a Material Adverse Effect. All payments due from the Borrower, or for which any claim may be made against the Borrower, on account of wages and employee health and welfare insurance and other benefits, have been paid or accrued as a liability on the books of the Borrower except where the failure to do so could not reasonably be expected to result in a Material Adverse Effect. The execution, delivery and performance of the Loan Documents and the consummation of the transactions contemplated thereby will not give rise to any right of termination or right of renegotiation on the part of any union under any collective bargaining agreement to which the Borrower or any of its Subsidiaries is bound.

SECTION 3.16 Solvency. Immediately after the execution, delivery and performance of the Loan Documents and the consummation of the transactions contemplated

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thereby on the Effective Date and immediately following the making of each Loan and after giving effect to the application of the proceeds of each Loan, (a) the fair value of the properties of each Loan Party (individually and on a consolidated basis with its Subsidiaries, and determined on a going concern basis) will exceed the probable liability of its debts and other liabilities, subordinated, contingent or otherwise; (b) the present fair saleable value of the property of each Loan Party (individually and on a consolidated basis with its Subsidiaries) will be greater than the amount that will be required to pay the probable liability of its debts and other liabilities, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured; (c) each Loan Party (individually and on a consolidated basis with its Subsidiaries) will be able to pay its debts and liabilities, subordinated, contingent or otherwise, as such debts and liabilities become absolute and matured; and (d) each Loan Party (individually and on a consolidated basis with its Subsidiaries) will not have unreasonably small capital with which to conduct its business in which it is engaged as such business is now conducted and is proposed to be conducted following the Effective Date.

SECTION 3.17 Employee Benefit Plans. Each Loan Party and its ERISA Affiliates is in compliance in all material respects with the applicable provisions of ERISA and the Code and the regulations and published interpretations thereunder. No ERISA Event has occurred or is reasonably expected to occur that, when taken together with all other such ERISA Events, could reasonably be expected to result in material liability of any Loan Party or any of its ERISA Affiliates or the imposition of a Lien on any of the property of any Loan Party. The present value of all accumulated benefit obligations of all underfunded Plans (based on the assumptions used for purposes of Statement of Financial Accounting Standards No. 87) did not, as of the date of the most recent financial statements reflecting such amounts, exceed by more than $250,000 the fair market value of the property of all such underfunded Plans. Using actuarial assumptions and computation methods consistent with subpart I of subtitle E of Title IV of ERISA, the aggregate liabilities of each Loan Party or its ERISA Affiliates to all Multiemployer Plans in the event of a complete withdrawal therefrom, as of the close of the most recent fiscal year of each such Multiemployer Plan, could not reasonably be expected to result in a Material Adverse Effect.

SECTION 3.18 Real Property. The Borrower does not own or lease any material Real Property or own, lease or operate any material facility on any Real Property other than pursuant to the lease agreement entered into as of April 22, 2008, with Bryan Tower II, L.P. as lessor and the Borrower as lessee.

SECTION 3.19 Insurance. All material insurance maintained by the Borrower is in full force and effect. The Borrower has insurance in such amounts and covering such risks and liabilities as are customary for companies of a similar size engaged in similar businesses in similar locations.

SECTION 3.20 Anti-Terrorism Law. No Loan Party and, to the knowledge of the Loan Parties, none of its Affiliates is in violation of any Requirement of Law relating to terrorism or money laundering (“Anti-Terrorism Laws”), including Executive Order No. 13224 on Terrorist Financing, effective September 24, 2001 (the “Executive Order”), and the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, Public Law 107-56.

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No Loan Party and to the knowledge of the Loan Parties, no Affiliate or broker or other agent of any Loan Party acting or benefiting in any capacity in connection with the Loans is any of the following:

(i) a person that is listed in the annex to, or is otherwise subject to the provisions of, the Executive Order;

(ii) a person owned or controlled by, or acting for or on behalf of, any person that is listed in the annex to, or is otherwise subject to the provisions of, the Executive Order;

(iii) a person with which any Lender is prohibited from dealing or otherwise engaging in any transaction by any Anti-Terrorism Law;

(iv) a person that commits, threatens or conspires to commit or supports “terrorism” as defined in the Executive Order; or

(v) a person that is named as a “specially designated national and blocked person” on the most current list published by the U.S. Treasury Department Office of Foreign Assets Control (“OFAC”) at its official website or any replacement website or other replacement official publication of such list.

No Loan Party and, to the knowledge of the Loan Parties, no broker or other agent of any Loan Party acting in any capacity in connection with the Loans (i) conducts any business or engages in making or receiving any contribution of funds, goods or services to or for the benefit of any person described in paragraph (b) above, (ii) deals in, or otherwise engages in any transaction relating to, any property or interests in property blocked pursuant to the Executive Order, or (iii) engages in or conspires to engage in any transaction that evades or avoids, or has the purpose of evading or avoiding, or attempts to violate, any of the prohibitions set forth in any Anti-Terrorism Law.

ARTICLE IV

CONDITIONS PRECEDENT

SECTION 4.01 Conditions to the Initial Loans. The obligation of each Lender to make its initial Loans shall be subject to the satisfaction (or waiver thereof) of each of the conditions precedent set forth below.

(a) Loan Documents. The Administrative Agent shall have received (i) on or before the Effective Date true and complete copies of the Loan Documents, all of which shall have been duly authorized, executed and delivered by the Loan Parties thereto and shall be in full force and effect, and (ii) on or before the date of making the initial Loan, each of the related agreements, documents, instruments and other items set forth on the closing checklist attached hereto as Exhibit F, each in form and substance reasonably satisfactory to the Administrative Agent in all material respects.

(b) Amendment Agreement. The Administrative Agent shall have received on or before the Effective Date a true and correct copy of the Amendment Agreement, which shall have been duly authorized, executed and delivered by the parties thereto, in form and substance reasonably satisfactory to the Administrative Agent in all material respects.

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(c) Investment Agreement. The Administrative Agent shall have received on or before the Effective Date a true and correct copy of the Investment Agreement, which shall have been duly authorized, executed and delivered by the parties thereto, in form and substance reasonably satisfactory to the Administrative Agent in all material respects.

SECTION 4.02 Conditions to All Loans. The obligation of each Lender to make any Loan (including the initial Loan) shall be subject to, and to the satisfaction of, each of the conditions precedent set forth below.

(a) Notice. The Administrative Agent shall have received a Borrowing Request as required by Section 2.03 (or such notice shall have been deemed given in accordance with Section 2.03).

(b) No Default. No Default has occurred and is continuing or would result from the making of such Loan or from the application of the proceeds therefrom.

(c) Representations and Warranties. Each of the representations and warranties made by any Loan Party set forth in (i) Article III hereof or in any other Loan Document and (ii) Article III of the Amended Credit Agreement (without giving effect to any amendment, modification, supplement or waiver thereof after the Effective Date other than giving effect to the Amendment Agreement upon the occurrence of the Amendment Effective Date) shall be true and correct in all material respects on and as of the date of such Loan with the same effect as though made on and as of such date, except to the extent such representations and warranties expressly relate to an earlier date.

The delivery of a Borrowing Request and the acceptance by Borrower of the proceeds of such Loan shall constitute a representation and warranty by Borrower and each other Loan Party that on the date of such Loan (both immediately before and after giving effect to such Loan and the application of the proceeds thereof) the conditions contained in Sections 4.02(b) and (c) have been satisfied. Borrower shall provide such information as the Administrative Agent may reasonably request to confirm that the conditions in Sections 4.02(b) and (c) have been satisfied.

ARTICLE V

COVENANTS

So long as this Agreement shall remain in effect and until the Commitments have been terminated and the principal of and interest on each Loan, all Fees and all other expenses or amounts payable under any Loan Document shall have been paid in full, unless the Required Lenders shall otherwise consent in writing, each Loan Party covenants and agrees with each Lender that:

SECTION 5.01 Indenture Covenants. The Borrower shall (i) comply with, and cause its Subsidiaries to comply with, in each case in all material respects, each of the covenants set forth in Article 4 of the Indenture, without giving effect to any amendment, modification, supplement or waiver thereof after the Effective Date and (ii) deliver a copy to the

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Administrative Agent of each material notice, report, statement, filing, certificate, resolution, item or document delivered by or on behalf of the Borrower or received by or on behalf of the Borrower pursuant to Article 4 and Article 6 of the Indenture concurrently upon such delivery or receipt.

SECTION 5.02 Amended Credit Agreement Covenants. Each of the Guarantors shall (i) comply in all material respects with each of the covenants set forth in the Amended Credit Agreement, without giving effect to any amendment, modification, supplement or waiver thereof after the Effective Date (other than giving effect to the Amendment Agreement upon the occurrence of the Amendment Effective Date) and (ii) deliver a copy to the Administrative Agent of each material notice, report, statement, filing, certificate, resolution, item or document delivered by or on behalf of any Guarantor or received by or on behalf of any Guarantor pursuant to Article V, Article VI and Article VIII of the Amended Credit Agreement (which shall give effect to the Amendment Agreement upon the occurrence of the Amendment Effective Date) concurrently upon such delivery or receipt.

SECTION 5.03 Financial Information; Compliance. Each Loan Party shall, and shall cause each of its Subsidiaries to furnish to the Administrative Agent and each Lender promptly, from time to time, such information regarding the operations, business affairs and financial condition of each Company, or compliance with the terms of any Loan Document, as the Administrative Agent or any Lender may reasonably request.

SECTION 5.04 Litigation and Other Notices. Each Loan Party shall, and shall cause each of its Subsidiaries to furnish to the Administrative Agent and each Lender written notice of the following promptly (and, in any event, within three Business Days of knowledge thereof):

(a) any Default, specifying the nature and extent thereof and the corrective action (if any) taken or proposed to be taken with respect thereto;

(b) the filing or commencement of, or any threat or notice of intention of any person to file or commence, any action, suit, litigation or proceeding, whether at law or in equity by or before any Governmental Authority, (i) against any Company, or any Affiliate thereof, that could reasonably be expected to result in a Material Adverse Effect or (ii) with respect to any Loan Document;

(c) any development that has resulted in, or could reasonably be expected to result in a Material Adverse Effect; and

(d) any material change in the accounting policies or financial reporting practices of the Loan Parties.

SECTION 5.05 Access to Properties and Inspections. Each Loan Party shall, and shall cause each of its Subsidiaries to keep proper books of record and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law are made of all dealings and transactions in relation to its business and activities and to permit any representatives designated by the Administrative Agent or any Lender to visit and inspect the financial records and the property of such Loan Party at reasonable times during normal business

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hours and as often as reasonably requested and at such time to make extracts from and copies of such financial records (provided that so long as no Event of Default has occurred and is continuing the Lenders shall be entitled to only one such visit per year coordinated by the Administrative Agent and each other visit by the Administrative Agent shall be at its expense), and permit any representatives designated by the Administrative Agent or any Lender to discuss the affairs, finances, accounts and condition of any Loan Party with the officers and employees thereof and advisors therefor (including independent accountants).

SECTION 5.06 Use of Proceeds. The Borrower shall use the proceeds of the Loans only for the purposes set forth in Section 3.12.

SECTION 5.07 Additional Guarantors. With respect to any person that is or becomes a Subsidiary after the Effective Date (other than a Joint Venture or RIGS; provided that for the purposes of this Section 5.07, RIGS shall be a Subsidiary subject to the terms of this Section 5.07 if the Amendment Effective Date does not occur by April 30, 2009), it shall promptly (and in any event within 30 days after such person becomes a Subsidiary) cause such new Subsidiary to execute a Joinder Agreement or such comparable documentation to become a Guarantor. Notwithstanding the foregoing, no Foreign Subsidiary shall be required to take the actions specified in the immediately preceding sentence of this Section 5.07, if doing so would constitute an investment of earnings in United States property under Section 956 (or a successor provision) of the Code, which investment would or could reasonably be expected to trigger a material increase in the net income of a United States shareholder of such Subsidiary pursuant to Section 951 (or a successor provision) of the Code; provided that this exception shall not apply to (A) Voting Stock of any Subsidiary which is a first-tier controlled foreign corporation (as defined in Section 957(a) of the Code) representing 66% of the total voting power of all outstanding Voting Stock of such Subsidiary and (B) 100% of the Equity Interests not constituting Voting Stock of any such Subsidiary, except that any such Equity Interests constituting “stock entitled to vote” within the meaning of Treasury Regulation Section 1.956 -2(c)(2) shall be treated as Voting Stock for purposes of this Section 5.07.

SECTION 5.08 Further Assurances. Each Loan Party shall, and shall cause each of its Subsidiaries to, upon the exercise by the Administrative Agent or any Lender of any power, right, privilege or remedy pursuant to any Loan Document which requires any consent, approval, registration, qualification or authorization of any Governmental Authority, execute and deliver all applications, certifications, instruments and other documents and papers that the Administrative Agent or such Lender may require.

SECTION 5.09 Notice of Effectiveness of Amendment Agreement. It shall furnish to the Administrative Agent and each Lender written notice of the occurrence of the Amendment Effective Date (and if such date does not occur on or before April 30, 2009, prompt written notice thereof).

SECTION 5.10 Anti-Terrorism Law; Anti-Money Laundering.

(a) No Loan Party shall, nor shall they cause or permit any Subsidiaries to directly or indirectly, (i) knowingly conduct any business or engage in making or receiving any contribution of funds, goods or services to or for the benefit of any person described in Section 3.20,

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(ii) knowingly deal in, or otherwise engage in any transaction relating to, any property or interests in property blocked pursuant to the Executive Order or any other Anti-Terrorism Law, or (iii) knowingly engage in or conspire to engage in any transaction that evades or avoids, or has the purpose of evading or avoiding, or attempts to violate, any of the prohibitions set forth in any Anti-Terrorism Law (and the Loan Parties shall deliver to the Lenders any certification or other evidence requested from time to time by any Lender in its reasonable discretion, confirming the Loan Parties’ compliance with this Section 5.10).

(b) No Loan Party shall, nor shall they cause or permit any Subsidiaries to cause or permit any of the funds of such Loan Party that are used to repay the Loans to be derived from any unlawful activity with the result that the making of the Loans would be in violation of any Requirement of Law.

SECTION 5.11 Embargoed Person. No Loan Party shall, nor shall they cause or permit any Subsidiaries to cause or permit (a) any of the funds or properties of the Loan Parties that are used to repay the Loans to constitute property of, or be beneficially owned directly or indirectly by, any person subject to sanctions or trade restrictions under United States law (“Embargoed Person” or “Embargoed Persons”) that is identified on (1) the “List of Specially Designated Nationals and Blocked Persons” maintained by OFAC and/or on any other similar list maintained by OFAC pursuant to any authorizing statute including, but not limited to, the International Emergency Economic Powers Act, 50 U.S.C. §§ 1701 et seq., The Trading with the Enemy Act, 50 U.S.C. App. 1 et seq., and any Executive Order or Requirement of Law promulgated thereunder, with the result that the investment in the Loan Parties (whether directly or indirectly) is prohibited by a Requirement of Law, or the Loans made by the Lenders would be in violation of a Requirement of Law, or (2) the Executive Order, any related enabling legislation or any other similar Executive Orders or (b) any Embargoed Person to have any direct or indirect interest, of any nature whatsoever in the Loan Parties, with the result that the investment in the Loan Parties (whether directly or indirectly) is prohibited by a Requirement of Law or the Loans are in violation of a Requirement of Law.

ARTICLE VI

GUARANTEE

SECTION 6.01 The Guarantee. The Guarantors hereby jointly and severally guarantee, as a primary obligor and not as a surety to the Administrative Agent and each Lender and their respective successors and assigns, the prompt payment in full when due (whether at stated maturity, by required prepayment, declaration, demand, by acceleration or otherwise) of the principal of and interest (including any interest, fees, costs or charges that would accrue but for the provisions of the Title 11 of the United States Code after any bankruptcy or insolvency petition under Title 11 of the United States Code) on the Loans made by the Lenders to, and the Notes held by each Lender of, Borrower, and all other Obligations from time to time owing to the Administrative Agent and/or the Lenders by any Loan Party under any Loan Document, in each case strictly in accordance with the terms thereof (such obligations being herein collectively called the “Guaranteed Obligations”). The Guarantors hereby jointly and severally agree that if Borrower or other Guarantor(s) shall fail to pay in full when due (whether at stated maturity, by acceleration or otherwise) any of the Guaranteed Obligations, the Guarantors will promptly pay the same in cash, without any demand or notice whatsoever, and that in the case of any

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extension of time of payment or renewal of any of the Guaranteed Obligations, the same will be promptly paid in full when due (whether at extended maturity, by acceleration or otherwise) in accordance with the terms of such extension or renewal.

SECTION 6.02 Obligations Unconditional. The obligations of the Guarantors under Section 6.01 shall constitute a guaranty of payment and to the fullest extent permitted by applicable Requirements of Law, are absolute, irrevocable and unconditional, joint and several, irrespective of the value, genuineness, validity, regularity or enforceability of the Guaranteed Obligations of Borrower under this Agreement, the Notes, if any, or any other agreement or instrument referred to herein or therein, or any substitution, release or exchange of any other guarantee of or security for any of the Guaranteed Obligations, and, irrespective of any other circumstance whatsoever that might otherwise constitute a legal or equitable discharge or defense of a surety or Guarantor (except for payment in full). Without limiting the generality of the foregoing, it is agreed that the occurrence of any one or more of the following shall not alter or impair the liability of the Guarantors hereunder which shall remain absolute, irrevocable and unconditional under any and all circumstances as described above:

(i) at any time or from time to time, without notice to the Guarantors, the time for any performance of or compliance with any of the Guaranteed Obligations shall be extended, or such performance or compliance shall be waived;

(ii) any of the acts mentioned in any of the provisions of this Agreement or the Notes, if any, or any other agreement or instrument referred to herein or therein shall be done or omitted;

(iii) the maturity of any of the Guaranteed Obligations shall be accelerated, or any of the Guaranteed Obligations shall be amended in any respect, or any right under the Loan Documents or any other agreement or instrument referred to herein or therein shall be amended or waived in any respect or any other guarantee of any of the Guaranteed Obligations or any security therefor shall be released or exchanged in whole or in part or otherwise dealt with;

(iv) any Lien or security interest granted to, or in favor of any Lender or the Administrative Agent as security for any of the Guaranteed Obligations shall fail to be perfected; or

(v) the release of any other Guarantor pursuant to Section 6.09.

The Guarantors hereby expressly waive diligence, presentment, demand of payment, protest and all notices whatsoever, and any requirement that the Administrative Agent or any Lender exhaust any right, power or remedy or proceed against Borrower under this Agreement or the Notes, if any, or any other agreement or instrument referred to herein or therein, or against any other person under any other guarantee of, or security for, any of the Guaranteed Obligations. The Guarantors waive any and all notice of the creation, renewal, extension, waiver, termination or accrual of any of the Guaranteed Obligations and notice of or proof of reliance by the Administrative Agent or any Lender upon this Guarantee or acceptance of this Guarantee, and the Guaranteed Obligations, and any of them, shall conclusively be deemed to

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have been created, contracted or incurred in reliance upon this Guarantee, and all dealings between Borrower and the Administrative Agent and/or any Lender shall likewise be conclusively presumed to have been had or consummated in reliance upon this Guarantee. This Guarantee shall be construed as a continuing, absolute, irrevocable and unconditional guarantee of payment without regard to any right of offset with respect to the Guaranteed Obligations at any time or from time to time held by the Administrative Agent and/or any Lender, and the obligations and liabilities of the Guarantors hereunder shall not be conditioned or contingent upon the pursuit by the Administrative Agent and/or any Lender or any other person at any time of any right or remedy against Borrower or against any other person which may be or become liable in respect of all or any part of the Guaranteed Obligations or against any collateral security or guarantee therefor or right of offset with respect thereto. This Guarantee shall remain in full force and effect and be binding in accordance with and to the extent of its terms upon the Guarantors and the successors and assigns thereof, and shall inure to the benefit of the Administrative Agent and each Lender, and their respective successors and assigns, notwithstanding that from time to time during the term of this Agreement there may be no Guaranteed Obligations outstanding.

SECTION 6.03 Reinstatement. The obligations of the Guarantors under this Article VI shall be automatically reinstated if and to the extent that for any reason any payment by or on behalf of Borrower or other Loan Party in respect of the Guaranteed Obligations is rescinded or must be otherwise restored by any holder of any of the Guaranteed Obligations, whether as a result of any proceedings in bankruptcy or reorganization or otherwise.

SECTION 6.04 Subrogation; Subordination. Each Guarantor hereby agrees that until the indefeasible payment and satisfaction in full in cash of all Guaranteed Obligations and the expiration and termination of the Commitments it shall waive any claim and shall not exercise any right or remedy, direct or indirect, arising by reason of any performance by it of its guarantee in Section 6.01, whether by subrogation or otherwise, against Borrower or any other Guarantor of any of the Guaranteed Obligations or any security for any of the Guaranteed Obligations.

SECTION 6.05 Remedies. The Guarantors jointly and severally agree that, as between the Guarantors and the Lenders, the obligations of Borrower under this Agreement and the Notes, if any, may be declared to be forthwith due and payable as provided in Section 7.01 (and shall be deemed to have become automatically due and payable in the circumstances provided in Section 7.01) for purposes of Section 6.01, notwithstanding any stay, injunction or other prohibition preventing such declaration (or such obligations from becoming automatically due and payable) as against Borrower and that, in the event of such declaration (or such obligations being deemed to have become automatically due and payable), such obligations (whether or not due and payable by Borrower) shall forthwith become due and payable by the Guarantors for purposes of Section 6.01.

SECTION 6.06 Instrument for the Payment of Money. Each Guarantor hereby acknowledges that the guarantee in this Article VI constitutes an instrument for the payment of money, and consents and agrees that any Lender or the Administrative Agent, at its sole option, in the event of a dispute by such Guarantor in the payment of any moneys due hereunder, shall have the right to bring a motion-action under New York CPLR Section 3213.

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SECTION 6.07 Continuing Guarantee. The guarantee in this Article VI is a continuing guarantee of payment, and shall apply to all Guaranteed Obligations whenever arising.

SECTION 6.08 General Limitation on Guarantee Obligations. In any action or proceeding involving any state corporate limited partnership or limited liability company law, or any applicable state, federal or foreign bankruptcy, insolvency, reorganization or other law affecting the rights of creditors generally, if the obligations of any Guarantor under Section 6.01 would otherwise be held or determined to be void, voidable, invalid or unenforceable, or subordinated to the claims of any other creditors, on account of the amount of its liability under Section 6.01, then, notwithstanding any other provision to the contrary, the amount of such liability shall, without any further action by such Guarantor, any Loan Party or any other person, be automatically limited and reduced to the highest amount that is valid and enforceable and not subordinated to the claims of other creditors as determined in such action or proceeding.

SECTION 6.09 Release of Guarantors. If, in compliance with the terms and provisions of the Loan Documents, all or substantially all of the Equity Interests or property of any Guarantor are sold or otherwise transferred (a “Transferred Guarantor”) to a person or persons, none of which is Borrower or a Subsidiary, such Transferred Guarantor shall, upon the consummation of such sale or transfer, be released from its obligations under this Agreement (including under Section 9.03 hereof).

ARTICLE VII

EVENTS OF DEFAULT

SECTION 7.01 Events of Default. Upon the occurrence and during the continuance of the following events (“Events of Default”):

(a) default shall be made in the payment of any principal of any Loan when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment (whether voluntary or mandatory) thereof or by acceleration thereof or otherwise;

(b) default shall be made in the payment of any interest on any Loan or any Fee or any other amount (other than an amount referred to in paragraph (a) above) due under any Loan Document, when and as the same shall become due and payable, and such default shall continue unremedied for a period of three Business Days;

(c) any representation or warranty made or deemed made in or in connection with or pursuant to any Loan Document or in any notice or certificate delivered hereunder, shall prove to have been false or misleading in any material respect when so made, deemed made or furnished;

(d) default shall be made in the due observance or performance by any Company of any covenant, condition or agreement contained in Section 5.04(a) or Section 5.06;

(e) default shall be made in the due observance or performance by any Company of any covenant, condition or agreement contained in any Loan Document (other than

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those specified in paragraphs (a), (b) or (d) immediately above) and such default shall continue unremedied or shall not be waived for a period of 30 days after written notice thereof from the Administrative Agent or any Lender to Borrower;

(f) any Company shall (i) fail to pay any principal or interest, regardless of amount, due in respect of any Indebtedness (other than the Obligations), when and as the same shall become due and payable beyond any applicable grace period, or (ii) fail to observe or perform any other term, covenant, condition or agreement contained in any agreement or instrument evidencing or governing any such Indebtedness if the effect of any failure referred to in this clause (ii) is to cause, or to permit the holder or holders of such Indebtedness or a trustee or other representative on its or their behalf (with or without the giving of notice, the lapse of time or both) to cause, such Indebtedness to become due prior to its stated maturity or become subject to a mandatory offer purchase by the obligor; provided that it shall not constitute an Event of Default pursuant to this paragraph (f) unless the aggregate amount of all such Indebtedness referred to in clauses (i) and (ii) exceeds $10.0 million at any one time (provided that, in the case of Hedging Obligations, the amount counted for this purpose shall be the amount payable by all Companies if such Hedging Obligations were terminated at such time);

(g) an involuntary proceeding shall be commenced or an involuntary petition shall be filed in a court of competent jurisdiction seeking (i) relief in respect of any Company, or of a substantial part of the property of any Company, under Title 11 of the United States Code, as now constituted or hereafter amended, or any other federal, state or foreign bankruptcy, insolvency, receivership or similar law; (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for any Company or for a substantial part of the property of any Company; or (iii) the winding-up or liquidation of any Company; and such proceeding or petition shall continue undismissed and unstayed for 60 days or an order or decree approving or ordering any of the foregoing shall be entered;

(h) any Company shall (i) voluntarily commence any proceeding or file any petition seeking relief under Title 11 of the United States Code, as now constituted or hereafter amended, or any other federal, state or foreign bankruptcy, insolvency, receivership or similar law; (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or the filing of any petition described in clause (g) above; (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for any Company or for a substantial part of the property of any Company; (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding; (v) make a general assignment for the benefit of creditors; (vi) admit in writing its inability or fail generally to pay its debts as they become due; (vii) take any action for the purpose of effecting any of the foregoing; or (viii) wind up or liquidate except as expressly permitted under the Indenture or Amended Credit Agreement, as applicable;

(i) one or more judgments, orders or decrees for the payment of money in an aggregate amount in excess of $10.0 million (that are not covered by insurance from an insurance company with an A.M. Best financial strength rating of at least A-, it being understood that even if such amounts are covered by insurance from such an insurance company such amounts shall count against such basket if responsibility for such amounts has been denied by such insurance company) shall be rendered against any Company or any combination thereof and

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the same shall remain undischarged, unvacated or unbonded for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to levy upon properties of any Company to enforce any such judgment;

(j) one or more ERISA Events shall have occurred that, in the opinion of the Required Lenders, when taken together with all other such ERISA Events, could reasonably be expected to result in a Material Adverse Effect;

(k) any Loan Document or any material provisions thereof shall at any time and for any reason be declared by a court of competent jurisdiction to be null and void, or a proceeding shall be commenced by any Loan Party or any other person, or by any Governmental Authority, seeking to establish the invalidity or unenforceability thereof (exclusive of questions of interpretation of any provision thereof), or any Loan Party shall repudiate or deny any portion of its liability or obligation for the Obligations; or

(l) there shall have occurred a Change in Control;

then, and in every such event (other than an event with respect to Borrower described in paragraph (g) or (h) above), and at any time thereafter during the continuance of such event, the Administrative Agent may, and at the request of the Required Lenders shall, by notice to Borrower, take either or both of the following actions, at the same or different times: (i) terminate forthwith the Commitments and (ii) declare the Loans then outstanding to be forthwith due and payable in whole or in part, whereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and any unpaid accrued Fees and all other Obligations of Borrower accrued hereunder and under any other Loan Document, shall become forthwith due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by Borrower and the Guarantors, anything contained herein or in any other Loan Document to the contrary notwithstanding; and in any event, with respect to Borrower described in paragraph (g) or (h) above, the Commitments shall automatically terminate and the principal of the Loans then outstanding, together with accrued interest thereon and any unpaid accrued Fees and all other Obligations of Borrower accrued hereunder and under any other Loan Document, shall automatically become due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by Borrower and the Guarantors, anything contained herein or in any other Loan Document to the contrary notwithstanding.

SECTION 7.02 Rescission. If at any time after termination of the Commitments or acceleration of the maturity of the Loans, Borrower shall pay all arrears of interest and all payments on account of principal of the Loans owing by it that shall have become due otherwise than by acceleration (with interest on principal and, to the extent permitted by law, on overdue interest, at the rates specified herein) and all Defaults (other than non-payment of principal of and accrued interest on the Loans due and payable solely by virtue of acceleration) shall be remedied or waived pursuant Section 9.02, then upon the written consent of the Required Lenders and written notice to Borrower, the termination of the Commitments or the acceleration and their consequences may be rescinded and annulled; but such action shall not affect any subsequent Default or impair any right or remedy consequent thereon. The provisions of the preceding sentence are intended merely to bind the Lenders to a decision that may be made at the

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election of the Required Lenders, and such provisions are not intended to benefit Borrower and do not give Borrower the right to require the Lenders to rescind or annul any acceleration hereunder, even if the conditions set forth herein are met.

ARTICLE VIII

THE ADMINISTRATIVE AGENT

SECTION 8.01 Appointment and Authority. Each of the Lenders hereby irrevocably appoints General Electric Capital Corporation, to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes such Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to such Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Article are solely for the benefit of the Administrative Agent and the Lenders, and neither Borrower nor any other Loan Party shall have rights as a third party beneficiary of any of such provisions.

SECTION 8.02 Rights as a Lender. Each person serving as Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Administrative Agent and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include each person serving as Administrative Agent hereunder in its individual capacity. Such person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with Borrower or any Subsidiary or other Affiliate thereof as if such person were not the Administrative Agent hereunder and without any duty to account therefor to the Lenders.

SECTION 8.03 Exculpatory Provisions. The Administrative Agent shall not have any duties or obligations except those expressly set forth herein and in the other Loan Documents. Without limiting the generality of the foregoing, the Administrative Agent:

(i) shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

(ii) shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that such Administrative Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents); provided that such Administrative Agent shall not be required to take any action that, in its judgment or the judgment of its counsel, may expose such Administrative Agent to liability or that is contrary to any Loan Document or applicable Requirements of Law; and

(iii) shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to Borrower or any of its Affiliates that is communicated to or obtained by the person serving as such Agent or any of its Affiliates in any capacity.

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The Administrative Agent shall not be liable for any action taken or not taken by it (x) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as such Administrative Agent shall believe in good faith shall be necessary, under the circumstances as provided Section 9.02) or (y) in the absence of its own gross negligence or willful misconduct. The Administrative Agent shall not be deemed to have knowledge of any Default unless and until notice describing such Default is given to such Administrative Agent by Borrower or a Lender.

The Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document or (v) the satisfaction of any condition set forth in Article IV or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to such Agent. Without limiting the generality of the foregoing, the use of the term “agent” in this Agreement with reference to the Administrative Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law. Instead, such term us used merely as a matter of market custom and is intended to create or reflect only an administrative relationship between independent contracting parties.

SECTION 8.04 Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan that by its terms must be fulfilled to the satisfaction of a Lender, the Administrative Agent may presume that such condition is satisfactory to such Lender unless the Administrative Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Administrative Agent may consult with legal counsel (who may be counsel for Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

SECTION 8.05 Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub agents appointed by such Administrative Agent. The Administrative Agent and any such sub agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Article shall apply to any such sub agent and to the Related Parties of the Administrative Agent and any such sub agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

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SECTION 8.06 Resignation of Administrative Agent. The Administrative Agent may at any time give notice of its resignation to the Lenders and Borrower. Upon receipt of any such notice of resignation, the Required Lenders shall have the right, in consultation with Borrower, to appoint a successor, which shall be a bank with an office in the United States, or an Affiliate of any such bank with an office in the United States. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may on behalf of the Lenders, appoint a successor Administrative Agent meeting the qualifications set forth above provided that if the Administrative Agent shall notify Borrower and the Lenders that no qualifying person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (1) the retiring Administrative Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents and (2) all payments, communications and determinations provided to be made by, to or through an Agent shall instead be made by or to each Lender directly, until such time as the Required Lenders appoint a successor Administrative Agent as provided for above in this paragraph. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Administrative Agent, and the retiring Administrative Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents (if not already discharged therefrom as provided above in this paragraph). The fees payable by Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between Borrower and such successor. After the retiring Administrative Agent’s resignation hereunder and under the other Loan Documents, the provisions of this Article VIII and Section 9.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Administrative Agent was acting as Administrative Agent.

SECTION 8.07 Non-Reliance on Administrative Agent and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder.

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ARTICLE IX

MISCELLANEOUS

SECTION 9.01 Notices.

(a) Generally. Except in the case of notices and other communications expressly permitted to be given by telephone (and except as provided in paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopier as follows:

(i) if to any Loan Party, to Borrower at:

Regency Energy Partners LP

c/o Regency GP LP, its General Partner

c/o Regency GP LLC, its General Partner

2001 Bryan Street, Suite 3700

Dallas, Texas 75201

Attention: Stephen L. Arata

Telecopier No.: (214) 840-5515

E-mail: stephen.arata@regencygas.com

with a copy to:

Regency Energy Partners LP

c/o Regency GP LP, its General Partner

c/o Regency GP LLC, its General Partner

2001 Bryan Street, Suite 3700

Dallas, Texas 75201

Attention: Dan Fleckman

Telecopier No.: (214) 840-5515

E-mail: dan.fleckman@regencygas.com

(ii) if to the Administrative Agent, to it at:

General Electric Capital Corporation

c/o GE Energy Financial Services

800 Long Ridge Road

Stamford, CT 06927

Attention: Portfolio Manager – Regency Energy Partners Revolver

Fax: (203) 357-4890

(iii) if to a Lender, to it at its address (or telecopier number) set forth in its Administrative Questionnaire.

Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by telecopier shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient,

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shall be deemed to have been given at the opening of business on the next business day for the recipient). Notices delivered through electronic communications to the extent provided in paragraph (b) below, shall be effective as provided in said paragraph (b).

(b) Electronic Communications. Notices and other communications to the Lenders hereunder may (subject to Section 9.01(d)) be delivered or furnished by electronic communication (including e mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices to any Lender pursuant to Article II if such Lender has notified the Administrative Agent that it is incapable of receiving notices under such Article by electronic communication. The Administrative Agent or Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it (including as set forth in Section 9.01(d)); provided that approval of such procedures may be limited to particular notices or communications.

Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement); provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next business day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

(c) Change of Address, Etc. Any party hereto may change its address or telecopier number for notices and other communications hereunder by notice to the other parties hereto.

(d) Posting. Each Loan Party hereby agrees that it will provide to the Administrative Agent all information, documents and other materials that it is obligated to furnish to the Administrative Agent pursuant to this Agreement and any other Loan Document, including all notices, requests, financial statements, financial and other reports, certificates and other information materials, but excluding any such communication that (i) relates to a request for a new, or a conversion of an existing, Loan (including any election of an interest rate or interest period relating thereto), (ii) relates to the payment of any principal or other amount due under this Agreement prior to the scheduled date therefor, (iii) provides notice of any Default under this Agreement or (iv) is required to be delivered to satisfy any condition precedent to the effectiveness of this Agreement and/or any borrowing or other extension of credit hereunder (all such non-excluded communications, collectively, the “Communications”), by transmitting the Communications in an electronic/soft medium in a format reasonably acceptable to the Administrative Agent at sean.kelly@ge.com or at such other e-mail address(es) provided to Borrower from time to time or in such other form, including hard copy delivery thereof, as the Administrative Agent shall require. In addition, each Loan Party agrees to continue to provide the Communications to the Administrative Agent in the manner specified in this Agreement or any other Loan Document or in such other form, including hard copy delivery thereof, as the

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Administrative Agent shall require. Nothing in this Section 9.01 shall prejudice the right of the Administrative Agent, any Lender or any Loan Party to give any notice or other communication pursuant to this Agreement or any other Loan Document in any other manner specified in this Agreement or any other Loan Document or as the Administrative Agent shall require.

To the extent consented to by the Administrative Agent in writing from time to time, Administrative Agent agrees that receipt of the Communications by the Administrative Agent at its e-mail address(es) set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents.

Each Loan Party further agrees that Administrative Agent may make the Communications available to the Lenders by posting the Communications on Intralinks or a substantially similar electronic transmission system (the “Platform”). The Platform is provided “as is” and “as available.” The Administrative Agent does not warrant the accuracy or completeness of the Communications, or the adequacy of the Platform and expressly disclaim liability for errors or omissions in the communications. No warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by the Administrative Agent in connection with the Communications or the Platform. In no event shall the Administrative Agent or any of its Related Parties have any liability to the Loan Parties, any Lender or any other person for damages of any kind, including direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of any Loan Party’s or the Administrative Agent’s transmission of communications through the Internet, except to the extent the liability of such person is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from such person’s gross negligence or willful misconduct.

SECTION 9.02 Waivers; Amendment.

(a) Generally. No failure or delay by the Administrative Agent or any Lender in exercising any right or power hereunder or under any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of any Loan Document or consent to any departure by any Loan Party therefrom shall in any event be effective unless the same shall be permitted by this Section 9.02, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent or any Lender may have had notice or knowledge of such Default at the time. No notice or demand on Borrower in any case shall entitle Borrower to any other or further notice or demand in similar or other circumstances.

(b) Required Consents. Subject to Section 9.02(c), neither this Agreement nor any other Loan Document nor any provision hereof or thereof may be waived, amended,

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supplemented or modified except, in the case of this Agreement, pursuant to an agreement or agreements in writing entered into by Borrower and the Required Lenders or, in the case of any other Loan Document, pursuant to an agreement or agreements in writing entered into by the Administrative Agent and the Loan Party or Loan Parties that are party thereto, in each case with the written consent of the Required Lenders; provided that no such agreement shall be effective if the effect thereof would:

(i) increase the Commitment of any Lender without the written consent of such Lender (it being understood that no amendment, modification, termination, waiver or consent with respect to any condition precedent, covenant or Default shall constitute an increase in the Commitment of any Lender);

(ii) reduce the principal amount of any Loan or reduce the rate of interest thereon (other than interest pursuant to Section 2.06(c)), or reduce any Fees payable hereunder, or change the form or currency of payment of any Obligation, without the written consent of each Lender directly affected thereby (it being understood that any amendment or modification to the financial definitions in this Agreement shall not constitute a reduction in the rate of interest for purposes of this clause (ii));

(iii) (A) change the scheduled final maturity of any Loan, (B) postpone the date for payment of any interest or fees payable hereunder, (C) change the amount of, waive or excuse any such payment (other than waiver of any increase in the interest rate pursuant to Section 2.06(c)), or (D) postpone the scheduled date of expiration of any Commitment beyond the Maturity Date, in any case, without the written consent of each Lender directly affected thereby;

(iv) increase the maximum duration of Interest Periods hereunder, without the written consent of each Lender directly affected thereby;

(v) permit the assignment or delegation by Borrower of any of its rights or obligations under any Loan Document, without the written consent of each Lender;

(vi) release all or substantially all of the Guarantors from their Guarantee (except as expressly provided in Article VI), or limit their liability in respect of such Guarantee, without the written consent of each Lender;

(vii) change Section 2.13(b) or (c) in a manner that would alter the pro rata sharing of payments or setoffs required thereby or any other provision in a manner that would alter the pro rata allocation among the Lenders of Loan disbursements, including the requirements of Sections 2.02(a), without the written consent of each Lender directly affected thereby;

(viii) change any substantive provision of this Section 9.02(b) or (c), without the written consent of each Lender directly affected thereby;

(ix) change the percentage set forth in the definition of “Required Lenders,” or any other provision of any Loan Document (including this Section) specifying the number or percentage of Lenders required to waive, amend or modify any rights

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thereunder or make any determination or grant any consent thereunder, without the written consent of each Lender, other than to increase such percentage or number or to give any additional Lender or group of Lenders such right to waive, amend or modify or make any such determination or grant any such consent;

(x) change or waive any provision of Article IX as the same applies to the Administrative Agent, or any other provision hereof as the same applies to the rights or obligations of the Administrative Agent, in each case without the written consent of such Administrative Agent; or

(xi) expressly change or waive any condition precedent in Section 4.01 to any Loan without the written consent of the Required Lenders.

(c) Dissenting Lenders. If, in connection with any proposed change, waiver, discharge or termination of the provisions of this Agreement as contemplated by Section 9.02(b), the consent of the Required Lenders is obtained but the consent of one or more of such other Lenders whose consent is required is not obtained, then Borrower shall have the right to replace such non-consenting Lender or Lenders, so long as all non-consenting Lenders are so replaced (or, at the option of Borrower if the respective non-consenting Lenders’ consent is required with respect to less than all Loans (or related Commitments), to replace only the Commitments and/or Loans of the respective non-consenting Lender that gave rise to the need to obtain such Lender’s individual consent), with one or more persons pursuant to Section 2.15 so long as at the time of such replacement each such new Lender consents to the proposed change, waiver, discharge or termination.

SECTION 9.03 Expenses; Indemnity; Damage Waiver.

(a) Costs and Expenses. Borrower shall pay (i) all reasonable out of pocket expenses incurred by the Administrative Agent and its respective Affiliates (including the reasonable fees, charges and disbursements of counsel, and local counsel who specialize in gas and pipeline matters, for the Administrative Agent) in connection with the preparation, negotiation, execution, delivery and administration of this Agreement and the other Loan Documents or any amendments, modifications or waivers of the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all out of pocket expenses incurred by the Administrative Agent or any Lender (including the fees, charges and disbursements of any counsel, and local counsel who specialize in gas and pipeline matters, for the Administrative Agent, or any Lender), in connection with the enforcement or protection of its rights (A) in connection with this Agreement and the other Loan Documents, including its rights under this Section 9.03, or (B) in connection with the Loans made hereunder, including all such out of pocket expenses incurred during any workout, restructuring or negotiations in respect of such and (iii) all documentary and similar taxes and charges in respect of the Loan Documents.

(b) Indemnification by Borrower. Borrower shall indemnify the Administrative Agent (and any sub-agent thereof) and each Lender, and each Related Party of any of the foregoing persons (each such person being called an “Indemnitee”) against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related

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expenses (including the fees, charges and disbursements of any counsel, and local counsel who specialize in gas and pipeline matters, for any Indemnitee) incurred by any Indemnitee or asserted against any Indemnitee by any third party or by Borrower or any other Loan Party arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the performance by the parties hereto of their respective obligations hereunder or thereunder or the consummation of the transactions contemplated hereby or thereby, (ii) any Loan or the use or proposed use of the proceeds therefrom, (iii) any actual or alleged presence or Release or threatened Release of Hazardous Materials on, at, under or from any property owned, leased or operated by any Company at any time, or any Environmental Claim related in any way to any Company, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether based on contract, tort or any other theory, whether brought by a third party or by Borrower or any other Loan Party, and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses (x) are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or willful misconduct of such Indemnitee or (y) result from a claim brought by Borrower or any other Loan Party against an Indemnitee for breach in bad faith of such Indemnitee’s obligations hereunder or under any other Loan Document, if Borrower or such Loan Party has obtained a final and nonappealable judgment in its favor on such claim as determined by a court of competent jurisdiction; provided, further, that Borrower shall not be required to reimburse the legal fees and expenses of more than one outside counsel (in addition to any reasonably necessary special counsel and up to one local counsel in each applicable local jurisdiction) for all Indemnitees unless, in the reasonable written opinion of outside counsel to such Indemnitees, representation of all such Indemnitees would be inappropriate due to the existence of an actual or potential conflict of interest.

(c) Reimbursement by Lenders. To the extent that Borrower for any reason fails to indefeasibly pay any amount required under paragraph (a) or (b) of this Section 9.03 to be paid by it to the Administrative Agent (or any sub-agent thereof) or any Related Party of the foregoing, each Lender severally agrees to pay to the Administrative Agent (or any such subagent) or such Related Party, as the case may be, such Lender’s pro rata share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent (or any such sub-agent) in its capacity as such, or against any Related Party of the foregoing acting for the Administrative Agent (or any such sub-agent) in connection with such capacity. The obligations of the Lenders under this paragraph (c) are subject to the provisions of Section 2.13. For purposes hereof, a Lender’s “pro rata share” shall be determined based upon its share of the sum of the total outstanding Loans and unused Commitments at the time.

(d) Waiver of Consequential Damages, Etc. To the fullest extent permitted by applicable Requirements of Law, no Loan Party shall assert, and each Loan Party hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument

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contemplated hereby, the transactions contemplated hereby or thereby. No Indemnitee referred to in paragraph (b) above shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents or the transactions contemplated hereby or thereby.

(e) Payments. All amounts due under this Section shall be payable not later than 3 Business Days after demand therefor.

SECTION 9.04 Successors and Assigns.

(a) Successors and Assigns Generally. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Administrative Agent and each Lender, and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an Eligible Assignee in accordance with the provisions of paragraph (b) of this Section 9.04 or (ii) by way of participation in accordance with the provisions of paragraph (d) of this Section 9.04 (and any other attempted assignment or transfer by Borrower or any Lender shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in paragraph (d) of this Section and, to the extent expressly contemplated hereby, the other Indemnitees) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) Assignments by Lenders. Any Lender may at any time assign to one or more Eligible Assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans at the time owing to it); provided that

(i) except in the case of any assignment made in connection with the primary syndication of the Commitment and Loans by the Administrative Agent or an assignment of the entire remaining amount of the assigning Lender’s Commitment and the Loans at the time owing to it or in the case of an assignment to a Lender or an Affiliate of a Lender or an Approved Fund with respect to a Lender, the aggregate amount of the Commitment (which for this purpose includes Loans outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $5.0 million, in the case of any assignment in respect of Loans and/or Commitments, unless each of the Administrative Agent and, so long as no Event of Default has occurred and is continuing, Borrower otherwise consent (each such consent not to be unreasonably withheld or delayed) (provided that all amounts assigned shall be aggregated in calculating the $1.0 million minimum in the event of simultaneous assignments to or from two or more Lender Affiliates);

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(ii) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Loan or the Commitment assigned, except that this clause (ii) shall not prohibit any Lender from assigning all or a portion of its rights and obligations on a non-pro rata basis; and

(iii) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together, if the assignment is not to a Lender, an affiliate of a Lender or an Approved Fund, with a processing and recordation fee of $3,500, and the Eligible Assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

Subject to acceptance and recording thereof by the Administrative Agent pursuant to paragraph (c) of this Section 9.04, from and after the effective date specified in each Assignment and Assumption, the Eligible Assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.11, 2.12, 2.14 and 9.03 with respect to facts and circumstances occurring prior to the effective date of such assignment. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this paragraph shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (d) of this Section 9.04.

(c) Register. The Administrative Agent, acting solely for this purpose as an agent of Borrower, shall maintain at one of its offices at the address specified in Section 9.01(a)(ii) a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and Borrower, the Administrative Agent and the Lenders shall treat each person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d) Participations. Any Lender may at any time, without the consent of, or notice to, Borrower or the Administrative Agent sell participations to any person (other than a natural person or Borrower or any of Borrower’s Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Loans owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) Borrower, the Administrative Agent and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement.

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Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce the Loan Documents and to approve any amendment, modification or waiver of any provision of the Loan Documents; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clause (i), (ii) or (iii) of the first proviso to Section 9.02(b) that affects such Participant. Subject to paragraph (e) of this Section, Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.11, 2.12 and 2.14 (subject to the requirements of those Sections) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.08 as though it were a Lender, provided such Participant agrees to be subject to Section 2.13 as though it were a Lender.

(e) Limitations on Participant Rights. A Participant shall not be entitled to receive any greater payment under Sections 2.11, 2.12 and 2.14 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with Borrower’s prior written consent.

SECTION 9.05 Survival of Agreement. All covenants, agreements, representations and warranties made by the Loan Parties in the Loan Documents and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of the Loan Documents and the making of any Loans, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and so long as the Commitments have not expired or terminated. The provisions of Sections 2.11, 2.13, 2.14 and Article IX shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Commitments or the termination of this Agreement or any provision hereof.

SECTION 9.06 Counterparts; Integration; Effectiveness; Electronic Execution.

(a) Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement and the other Loan Documents, and any separate letter agreements with respect to fees payable to the Administrative Agent, constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and

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understandings, oral or written, relating to the subject matter hereof. This Agreement shall become effective when the conditions set forth in Section 4.01 are satisfied, and at such time, the signatures of the Administrative Agent and the Loan Parties to this Agreement shall be deemed to be the signatures of such Administrative Agent and Loan Parties to this Agreement. Delivery of an executed counterpart of a signature page of this Agreement by telecopier shall be effective as delivery of a manually executed counterpart of this Agreement.

(b) Electronic Execution of Assignments. The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Assumption shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable Requirement of Law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

SECTION 9.07 Severability. Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

SECTION 9.08 Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender and each of its respective Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by applicable Requirements of Law, to set off and apply any and all deposits (general or special, time or demand, provisional or final, in whatever currency) at any time held and other obligations (in whatever currency) at any time owing by such Lender or any such Affiliate to or for the credit or the account of Borrower or any other Loan Party against any and all of the obligations of Borrower or such Loan Party now or hereafter existing under this Agreement or any other Loan Document to such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement or any other Loan Document and although such obligations of Borrower or such Loan Party may be contingent or unmatured or are owed to a branch or office of such Lender different from the branch or office holding such deposit or obligated on such indebtedness. The rights of each Lender and its respective Affiliates under this Section are in addition to other rights and remedies (including other rights of setoff) that such Lender or its respective Affiliates may have. Each Lender agrees to notify Borrower and the Administrative Agent promptly after any such setoff and application; provided that the failure to give such notice shall not affect the validity of such setoff and application.

SECTION 9.09 Governing Law; Jurisdiction; Consent to Service of Process.

(a) Governing Law. This Agreement shall be construed in accordance with and governed by the law of the State of New York, without regard to conflicts of law principles that would require the application of the laws of another jurisdiction.

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(b) Submission to Jurisdiction. Each Loan Party hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York sitting in New York County and of the United States District Court of the Southern District of New York, and any appellate court from any thereof, in any action or proceeding arising out of or relating to any Loan Document, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State court or, to the fullest extent permitted by applicable law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement or any other Loan Document shall affect any right that the Administrative Agent or any Lender may otherwise have to bring any action or proceeding relating to this Agreement or any other Loan Document against any Loan Party or its properties in the courts of any jurisdiction.

(c) Waiver of Venue. Each Loan Party hereby irrevocably and unconditionally waives, to the fullest extent permitted by applicable Requirements of Law, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or any other Loan Document in any court referred to in Section 9.09(b). Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by applicable Requirements of Law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(d) Service of Process. Each party hereto irrevocably consents to service of process in any action or proceeding arising out of or relating to any Loan Document, in the manner provided for notices (other than telecopier) in Section 9.01. Nothing in this Agreement or any other Loan Document will affect the right of any party hereto to serve process in any other manner permitted by applicable Requirements of Law.

SECTION 9.10 Waiver of Jury Trial. Each Loan Party hereby waives, to the fullest extent permitted by applicable Requirements of Law, any right it may have to a trial by jury in any legal proceeding directly or indirectly arising out of or relating to this Agreement, any other Loan Document or the transactions contemplated hereby (whether based on contract, tort or any other theory). Each party hereto (a) certifies that no representative, agent or attorney of any other party has represented, expressly or otherwise, that such other party would not, in the event of litigation, seek to enforce the foregoing waiver and (b) acknowledges that it and the other parties hereto have been induced to enter into this Agreement by, among other things, the mutual waivers and certifications in this Section.

SECTION 9.11 Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

SECTION 9.12 Treatment of Certain Information; Confidentiality. Each of the Administrative Agent and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its Affiliates and to its and its Affiliates’ respective partners, directors, officers, employees, agents, advisors and other

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representatives (it being understood that the persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority purporting to have jurisdiction over it or its Affiliates (including any self-regulatory authority, such as the National Association of Insurance Commissioners), (c) to the extent required by applicable Requirements of Law or by any subpoena or similar legal process, (d) to any other party hereto, (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section 9.12, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement, (ii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to Borrower and its obligations or (iii) any rating agency for the purpose of obtaining a credit rating applicable to any Lender, (g) with the consent of Borrower or (h) to the extent such Information (x) becomes publicly available other than as a result of a breach of this Section or (y) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than Borrower. For purposes of this Section, “Information” means all information received from Borrower or any of its Subsidiaries relating to Borrower or any of its Subsidiaries or any of their respective businesses, other than any such information that is available to the Administrative Agent or any Lender on a nonconfidential basis prior to disclosure by Borrower or any of its Subsidiaries; provided that, in the case of information received from Borrower or any of its Subsidiaries after the Effective Date, such information is clearly identified at the time of delivery as confidential. Any person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such person has exercised the same degree of care to maintain the confidentiality of such Information as such person would accord to its own confidential information.

SECTION 9.13 USA PATRIOT Act Notice. Each Lender that is subject to the Act (as hereinafter defined) and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies Borrower that pursuant to the requirements of the USA PATRIOT Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”), it is required to obtain, verify and record information that identifies Borrower, which information includes the name, address and tax identification number of Borrower and other information regarding Borrower that will allow such Lender or the Administrative Agent, as applicable, to identify Borrower in accordance with the Act. This notice is given in accordance with the requirements of the Act and is effective as to the Lenders and the Administrative Agent.

SECTION 9.14 Interest Rate Limitation. Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Loan, together with all fees, charges and other amounts which are treated as interest on such Loan under applicable Requirements of Law (collectively, the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”) which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan in accordance with applicable Requirements of Law, the rate of interest payable in respect of such Loan hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and Charges that would have been payable in respect of such Loan but were not payable as a result of the operation of this

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Section shall be cumulated and the interest and Charges payable to such Lender in respect of other Loans or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by such Lender.

SECTION 9.15 Obligations Absolute. To the fullest extent permitted by applicable Requirements of Law, all obligations of the Loan Parties hereunder shall be absolute and unconditional irrespective of:

(a) any bankruptcy, insolvency, reorganization, arrangement, readjustment, composition, liquidation or the like of any Loan Party;

(b) any lack of validity or enforceability of any Loan Document or any other agreement or instrument relating thereto against any Loan Party;

(c) any change in the time, manner or place of payment of, or in any other term of, all or any of the Obligations, or any other amendment or waiver of or any consent to any departure from any Loan Document or any other agreement or instrument relating thereto;

(d) any release or amendment or waiver of or consent to any departure from any guarantee, for all or any of the Obligations;

(e) any exercise or non-exercise, or any waiver of any right, remedy, power or privilege under or in respect hereof or any Loan Document; or

(f) any other circumstances which might otherwise constitute a defense available to, or a discharge of, the Loan Parties.

[Signature Pages Follow]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

The Borrower:
REGENCY ENERGY PARTNERS LP
By:	Regency GP LP, its General Partner
	By:	Regency GP LLC, its General Partner
By:	/s/ Stephen L. Arata
Name:	Stephen L. Arata
Title:	Executive Vice President and Chief Financial Officer

The Guarantors:
REGENCY GAS SERVICES LP
By:	Regency OLP GP, LLC, its General Partner
By:	/s/ Stephen L. Arata
Name:	Stephen L. Arata
Title:	Vice President

REGENCY FIELD SERVICES LLC
REGENCY LIQUIDS PIPELINE LLC
GULF STATES TRANSMISSION CORPORATION
REGENCY GAS MARKETING LLC
PUEBLO HOLDINGS, INC.
PUEBLO MIDSTREAM GAS CORPORATION
REGENCY OIL PIPELINE LLC
REGENCY GAS UTILITY LLC
CDM RESOURCE MANAGEMENT LLC
FRONTSTREET HUGOTON LLC
WGP-KHC, LLC
By:	/s/ Stephen L. Arata
	Stephen L. Arata
	Vice President
PALAFOX JOINT VENTURE
By:	Regency Field Services LLC, its Venturer
By:	/s/ Stephen L. Arata
	Stephen L. Arata
	Vice President
By:	Regency Gas Services LP, its Venturer
By:	Regency OLP GP LLC, its General Partner
By:	/s/ Stephen L. Arata
	Stephen L. Arata
	Vice President

GENERAL ELECTRIC CAPITAL CORPORATION, as Administrative Agent
By:	/s/ Matthew A. Toth, III
Name:	Matthew A. Toth, III
Title:	Authorized Signatory

GENERAL ELECTRIC CAPITAL CORPORATION, as Lender
By:	/s/ Matthew A. Toth, III
Name:	Matthew A. Toth, III
Title:	Authorized Signatory

Execution Copy

[General Electric Capital Corporation letterhead]

FEE LETTER

February 26, 2009

Regency Energy Partners LP

c/o Regency GP LP, its General Partner

c/o Regency GP LLC, its General Partner

2001 Bryan Street, Suite 3700

Dallas, Texas 75201

Attention: Stephen L. Arata

Re: Fee Letter

Gentlemen:

Reference is made to that certain Revolving Credit Agreement, dated as of the date hereof, among General Electric Capital Corporation (the “Administrative Agent”), Regency Energy Partners LP (the “Borrower”) and the Guarantors and Lenders party thereto (as such terms are defined in such agreement) (the “Credit Agreement”). All capitalized terms used but not defined herein shall have the respective meanings given to them in the Credit Agreement.

In addition to any fees or other amounts payable by the Borrower to the Administrative Agent and Lenders under the terms of the Credit Agreement and any deposits paid to the Administrative Agent and Lenders pursuant thereto or pursuant to any other agreement, the Borrower agrees to pay to the Administrative Agent the following fees and expenses:

(1) Closing Fee. A nonrefundable closing fee of 6% of the aggregate principal amount of the Commitments on the Effective Date, or U.S. $2,700,000, is due and payable in full on the Effective Date.

(2) Administration Fee. If by May 1, 2009 all outstanding Loans and interest due thereon under the Credit Agreement are not repaid in full and all Commitments under the Credit Agreement are not terminated, a nonrefundable annual administration fee of U.S. $75,000 per annum shall be due and payable in full on May 1, 2009, but relate back to the Effective Date, and on each anniversary of the Effective Date.

The Borrower acknowledges and agrees that the Administrative Agent may provide to industry trade organizations information with respect to the Commitments that is necessary and customary for inclusion in league table measurements.

Very truly yours,
GENERAL ELECTRIC CAPITAL CORPORATION
By:	/s/ Matthew A. Toth, III
Name:	Matthew A. Toth, III
Title:	Authorized Signatory

ACCEPTED and AGREED:
REGENCY ENERGY PARTNERS LP
By:	Regency GP LP, its General Partner
	By:	Regency GP LLC, its General Partner
By:	/s/ Stephen L. Arata
Name:	Stephen L. Arata
Title:	Executive Vice President and Chief Financial Officer

2

EX-12.1

Exhibit 12.1

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, 2008		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
Earnings:
Pre-tax income (loss) from continuing operations	$	101,062	$	(12,600	)	$	(7,244	)	$	(11,592	)	$	1,474		$	20,137
Add:
Interest expense		63,243		52,016			37,182			17,880			1,335			5,097
Portion of rent under long-term operating leases representative of an interest factor		677		477			574			477			43			468
Amortization of capitalized interest		279		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	$	165,261	$	40,036		$	30,111		$	6,453		$	2,796		$	25,982
Fixed Charges:
Interest expense		63,243		52,016			37,182			17,880			1,335			5,097
Portion of rent under long-term operating leases representative of an interest factor		677		477			574			477			43			468
Capitalized interest		2,409		1,754			511			2,613			—			—
Total fixed charges	$	66,329	$	54,247		$	38,267		$	20,970		$	1,378		$	5,565
Ratio of earnings to fixed charges (x times)(1)		2.49		—			—			—			2.03			4.67
(1) Earnings were insufficient to cover fixed charges by:	$	—	$	14,211		$	8,156		$	14,517		$	—		$	—

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES OF REGENCY ENERGY PARTNERS LP

All subsidiaries are wholly owned, directly or indirectly by Regency Energy Partners LP as of February 28, 2009.

• Regency OLP GP LLC

• Regency Energy Finance Corp.

• Regency Gas Services LP

• Regency Intrastate Gas LLC

• Regency Liquids Pipeline LLC

• Regency Gas Marketing LLC

• Gulf States Transmission Corporation

• Regency Field Services LLC

• Regency Gas Utility LLC

• Pueblo Holdings Inc.

• Pueblo Midstream Gas Corporation

• Regency Oil Pipeline LLC

• CDM Resource Management LLC

• FrontStreet Hugoton, LLC

• Regency NX, LLC

• WGP-KHC, LLC

EX-23.1

Exhibit 23.1

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 reports dated March 1, 2009, with respect to the consolidated balance sheets of Regency Energy Partners LP as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital for the years then ended, and the effectiveness of internal control over financial reporting as of December 31, 2008, which report appears in the December 31, 2008 annual report on Form 10-K of Regency Energy Partners LP.

Our report dated March 1, 2009, on the effectiveness of internal control over financial reporting as of December 31, 2008, contains an explanatory paragraph that states Regency Energy Partners LP acquired CDM Resource Management, Ltd. (CDM) during 2008 and management excluded from its assessment of the effectiveness of Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, CDM’s internal control over financial reporting associated with total assets of $881,552,000 and total revenues of $132,549,000 included in the consolidated financial statements of Regency Energy Partners LP and subsidiaries as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of Regency Energy Partners LP also excluded an evaluation of the internal control over financial reporting of CDM.

/s/    KPMG LLP

Dallas, Texas

March 1, 2009

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-140088 on Form S-8 and Registration Statement No. 333-141809 on Form S-3 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, 2008.

/s/    Deloitte & Touche LLP

Dallas, Texas

March 1, 2009

EX-31.1

Exhibit 31.1

I, Byron R. Kelley, certify that:

1. I have reviewed this annual report on Form 10-K of Regency Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities and Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2009	/s/    BYRON R. KELLEY
	Byron R. Kelley
	Chairman, Chief Executive Officer and President of Regency GP LLC, General Partner of Regency GP LP, General Partner of Regency Energy Partners LP

EX-31.2

Exhibit 31.2

I, Stephen L. Arata, certify that:

1. I have reviewed this annual report on Form 10-K of Regency Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities and Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2009	/s/    STEPHEN L. ARATA
	Stephen L. Arata
	Executive Vice-President and Chief Financial Officer of Regency GP LLC, General Partner of Regency GP LP, General Partner of Regency Energy Partners LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

OF REGENCY ENERGY PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying annual report on Form 10-K for the year ended December 31, 2008 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Byron R. Kelley, Chairman, Chief Executive Officer and President of Regency GP LLC, the general partner of Regency GP LP, the general partner of Regency Energy Partners LP (the “Partnership”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 1, 2009	/s/    BYRON R. KELLEY
	Byron R. Kelley
	Chairman, Chief Executive Officer and President of Regency GP LLC, General Partner of Regency GP LP, General Partner of Regency Energy Partners LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

OF REGENCY ENERGY PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying annual report on Form 10-K for the year ended December 31, 2008 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen L. Arata, Executive Vice-President and Chief Financial Officer of Regency GP LLC, the general partner of Regency GP LP, the general partner of Regency Energy Partners LP (the “Partnership”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 1, 2009	/s/    STEPHEN L. ARATA
	Stephen L. Arata
	Executive Vice-President and Chief Financial Officer of Regency GP LLC, General Partner of Regency GP LP, General Partner of Regency Energy Partners LP