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Article by DailyStocks_admin    (06-26-08 10:44 AM)

Regency Energy Partners LP. CEO James W Hunt bought 100000 shares on 6-17-2008 at $26.79

BUSINESS OVERVIEW

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.

We divide our operations into three business segments:

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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;
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Transportation: We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system; and
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Contract Compression: On January 15, 2008, we acquired CDM, which provides customers with turn-key natural gas compression services.

All of our midstream assets are located in well-established areas of natural gas production that are characterized by long-lived, predictable reserves. These areas are generally experiencing increased levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

BUSINESS STRATEGIES . Our management team is dedicated to increasing the amount of cash available for distribution to each outstanding unit while maintaining a strong balance sheet. We intend to achieve this by executing the following strategies:

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Implementing cost-effective organic growth opportunities. We intend to build natural gas gathering assets, processing facilities, field compression, and transportation lines that will enhance our existing systems, further our ability to aggregate supply, and enable us to access premium markets for that supply. Where applicable, we will seek to coordinate each expansion with the needs of significant producers in the area to mitigate speculative risk associated with securing through-put volumes.
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Maximizing the profitability of our existing assets. We intend to increase the profitability of our existing asset base by actively controlling and reducing operating costs, identifying new business opportunities, scaling our operations by adding new volumes of natural gas supplies, and undertaking additional initiatives to enhance efficiency.
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Continuing to reduce our exposure to commodity price risk. We operate our business in a manner designed to allow us to generate stable cash flows while mitigating the impact of fluctuations in commodity prices.
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Utilizing our relationship with GE EFS to facilitate acquisitions from third parties. We intend to pursue strategic acquisitions of midstream assets from third parties in or near our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of those assets. We also intend to pursue opportunities in new regions with significant natural gas reserves and high levels of drilling activity. We believe our relationship with GE EFS will provide increased access to such opportunities.
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Pursuing strategic acquisitions of midstream assets from GE EFS . GE EFS’s energy asset base is considerably larger than our own and includes midstream assets that we believe are strategically aligned with our existing operations or provide attractive operations in new regions. GE EFS does not have any obligation to sell assets to us. On January 8, 2008, however, we acquired FrontStreet, which owns a gas gathering system located in Kansas and Oklahoma, from affiliates of GECC.
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Improving our credit ratings. We are committed to achieving an investment grade rating on our debt. Our current credit ratings are BB- and Ba3.

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

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Our acquisition strategy and growth opportunities will benefit from our affiliation with GE EFS. As indicated above, we believe our affiliation with GE EFS enhances our ability to consummate accretive acquisitions and capitalize on market opportunities.
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We have the financial flexibility and adequate access to capital to pursue acquisition and organic growth opportunities. We remain committed to maintaining a capital structure that will afford us the financial strength to fund expansion projects and other attractive investment opportunities. We believe our relationship with GE increases our access to capital and enables us to pursue strategic opportunities that we might otherwise be unable to pursue. In addition, we have sufficient liquidity under our credit facility to fund our near term growth capital requirements.
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We have a significant market presence in major natural gas supply areas. We have a significant market presence in each of our operating areas, which are located in some of the largest and most prolific gas-producing regions of the United States: the Louisiana-Mississippi-Ala bama Salt basin in north Louisiana, the Permian basin of west Texas, the Hugoton and Anadarko basins in the mid-continent area in Kansas and Oklahoma, the Barnett Shale basin in north Texas, the East Texas basin and Edwards, Olmos and Wilcox trends in south Texas. Our geographical diversity reduces our reliance on any particular region, basin or gathering system. Each of these producing regions is well-established with generally long-lived, predictable reserves, and our assets are strategically located in each of the regions. These areas are experiencing high levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

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We have a m odern and efficient contract compressor fleet. Our highly standardized compressor fleet provides us with significant operational efficiencies and flexibility. At December 31, 2007, 73 percent of the total available horsepower in our contract compression segment was purchased new since December 31, 2003. We believe the young age and overall composition of our compressor fleet will result in fewer mechanical failures, lower fuel usage (a direct cost savings for our customers), and reduced environmental emissions. In addition, in developing and maintaining our standardized fleet, we have acquired increased technical proficiency in predictive and preventive maintenance and overhaul operations on our equipment, which helps us to achieve our mechanical availability commitments. We guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations.
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Our l arge horsepower contract compression installations have l ong-term commitments and provide stable , fee-based cash flows. The large horsepower applications on which we focus in our contract compression business segment generally result in long-term installations with our customers, which we believe improves the stability of our cash flows. Our contracts generally have initial terms ranging from one to five years. We charge our customers either a fixed monthly fee for our compression services, regardless of the volume of natural gas we compress in that month, or a fee based on the volume of natural gas compressed per month.
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Our Regency Intrastate Pipeline System provides us with significant fee-based transportation through-put volumes and cash flow. The Regency Intrastate Pipeline System allows us to capitalize on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. These transportation through-put volumes have limited commodity price exposure and provide us with a stable, fee-based cash flow.
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We have an experienced, knowledgeable management team with a proven track record. Our senior management team has an average of over 20 years of industry related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation and focus for managing and enhancing our operations, for accessing strategic acquisition opportunities and for constructing new assets. Additionally, members of our management team have a substantial economic interest in us through an indirect 8.2 percent economic interest in the General Partner and a 1.6 percent limited partner interest.

RECENT DEVELOPMENTS
Acquisition of Nexus. On February 22, 2008, we entered into an Agreement and Plan of Merger (the “Nexus Merger Agreement”) with Nexus Gas Partners, LLC, a Delaware limited liability company (“Nexus Member”), and Nexus Gas Holdings, LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”). The aggregate consideration to be paid is $85,000,000 in cash, subject to adjustment pursuant to customary closing adjustments. Nexus is a midstream provider of natural gas gathering, dehydration and compression services for producers in DeSoto Parish, La., and Shelby County, Texas. The Nexus gathering system consists of 80 miles of low- and high-pressure gathering pipelines and is currently gathering more than 110 MMCF per day from approximately 500 wells. In addition, u pon consummation of the Nexus Acquisition, we will acquire Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Southern Natural Gas Company (“Sonat”). Pursuant to the Sonat Agreement Nexus will purchase 136 miles of pipeline from Sonat that would enable the Nexus gathering system to be integrated into our north Louisiana asset base (the “Sonat Acquisition”). The Sonat Acquisition is subject to abandonment approval by the FERC and other customary closing conditions. Upon the closing of the Sonat Acquisition, we will pay Sonat $28,000,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, we will make an additional payment of $25,000,000 to the Nexus Member.

In connection with the closing of the Merger, $8,500,000 will be deposited with an escrow agent to secure certain indemnification obligations of Member under the Merger Agreement. The escrow will remain in place for one year after the closing of the Merger, and the balance of the escrow upon termination of the escrow (net of any pending claims) will be released to Member.

The Nexus Acquisition is subject to approval under the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing conditions. The closing is expected to occur in late first quarter or early second quarter 2008. We anticipate funding the Merger consideration through borrowings under the existing revolving credit facility.

Acquisition of CDM. On January 15, 2008, we acquired CDM for $695,314,000. The total purchase price, subject to customary post-closing adjustments, paid for the partnership interests of CDM consisted of (1) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $216,869,000, (2) the payment of an aggregate of $161,945,000 in cash to the CDM Partners, and (3) the assumption of $316,500,000 in CDM’s debt obligations. Of those Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement. CDM provides 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. CDM’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 field wide needs. CDM is responsible for the installation and ongoing operation, service, and repair of compressors, which we modify as necessary to adapt to our customers’ changing operating conditions. The CDM acquisition provides the Partnership with stable, fee based cash flows, a source of long-term organic growth projects, and provides synergies with the Partnership’s existing operations. CDM’s experienced management team, retained by us to operate our contract compression segment, has demonstrated an ability to deliver strong organic growth since its inception. CDM’s contract compression services will be reported as a separate business segment from the date of acquisition forward and will comprise the entire business segment.

Amendments to the Fourth Amended and Restated Revolving Credit Facility. We have amended our credit agreement three times (September 28, 2007, January 15, 2008, and February 13, 2008) to increase commitments under our revolving credit facility to $900,000,000. The availability for letters of credit is $100,000,000. We also have the option to request an additional $250,000,000 in revolving commitments with 10 business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the fourth amended and restated credit agreement, or the credit facility, have been met. These amendments were executed to primarily provide funding for organic growth projects and acquisitions.

Acquisition of FrontStreet . On January 7, 2008, the Partnership acquired all the outstanding equity (the “FrontStreet Acquisition”) of FrontStreet from ASC (an affiliate of GECC) and EnergyOne for $146,766,000. The total purchase price, subject to customary post-closing adjustments, paid by the Partnership for FrontStreet consisted of (1) the issuance of 4,701,034 Class E common units of the Partnership to ASC, which were valued at $135,014,000 and (2) the payment of $11,752,000 in cash to EnergyOne. FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party. FrontStreet’s gas gathering system has 63,500 horsepower and 1,875 miles of pipeline extending over nine counties in Kansas and Oklahoma. The FrontStreet acquisition provides the Partnership with stable, fee based cash flows and is expected to be immediately accretive to our unitholders.

Equity Offering. On July 26, 2007, we closed an underwritten public offering of 10,000,000 common units for $32.05 per unit and, on July 31, 2007, the underwriters exercised their option to purchase 1,500,000 additional common units. We received net proceeds of $353,832,000 from these offerings. We used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000). With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership repurchased $192,500,000, or 35 percent, of its outstanding senior notes which required us to pay an early redemption penalty of $16,122,000 in August 2007.

GE EFS acquisition of HM Capital ’ s interests in us and resulting cha nge in contro l . On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of GECC, acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners. Concurrently, Regency LP Acquirer LP, another indirect subsidiary of GECC, acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management team. As a part of this acquisition, affiliates of HM Capital Partners entered into an agreement not to sell or otherwise distribute 4,692,471 of the Partnership’s common units retained by it for a period of 180 days. In addition, a separate affiliate of HM Capital Partners entered into an agreement not to sell or otherwise distribute 3,406,099 of the Partnership’s common units retained by it for a period of one year.

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

Concurrent with the GE EFS acquisition of HM Capital's interest in us, 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 $25,544,000 or $24.00 per unit. Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

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

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-use 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 delivered to a processing 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 a fractionator, 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.

Overview of U.S. market. According to the EIA, the midstream natural gas industry in the United States includes approximately 530 processing plants that process approximately 40 Bcf of natural gas per day and produce approximately 73 million gallons per day of NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas wells. Natural gas 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 21.8 Tcf in 2006 to 24.3 Tcf in 2016, representing an average annual growth rate of 1.1 percent, with a slight decrease in consumption through the year 2030. During the five years ended December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, while total marketed domestic production averaged approximately 18.9 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

Gathering. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collect natural gas from points near producing wells and transport it to larger pipelines for further transportation. We own and operate 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. 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. Natural gas compression is a mechanical process in which a volume of gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Field compression is typically used to lower the entry pressure, while maintaining or increasing the exit pressure of a gathering system to allow it to operate at a lower receipt pressure and provide sufficient pressure to deliver gas into a higher pressure downstream pipeline. We operate more than 700,000 horsepower of compression in Texas, Louisiana, Oklahoma, Kansas and Arkansas.

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, 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 five geographic regions.

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. Natural gas processing not only removes unwanted NGLs that would interfere with pipeline transportation or use of the natural gas, but also extracts hydrocarbon liquids that can have higher value as NGLs. 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 and/or treating plants in five geographic regions.

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. We own and operate the Regency Intrastate Pipeline system, an intrastate natural gas pipeline system located in north Louisiana. We also own a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

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. Our gathering and processing operations are located in areas that have experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies.

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 through interstate or intrastate gas transportation pipelines.

The following table sets forth information regarding our gathering systems and processing plants as of December 31, 2007.

No rth Louisiana Region . Our north Louisiana region includes:
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the Dubach and Lisbon processing plants;
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the Dubach/Calhoun/Lisbon gathering system, which is a large integrated natural gas gathering and processing system located primarily in four parishes of north Louisiana; and
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the Elm Grove and Dubberly refrigeration plants.

This system is located in active drilling areas in north Louisiana. Through our Dubach/Calhoun/Lisbon gathering system and its interconnections with our Regency Intrastate Pipeline system in north Louisiana described in “—Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, marketing and transportation.

Natural Gas Supply. The natural gas supply for our north Louisiana gathering systems is derived primarily from natural gas wells located in Claiborne, Union, Lincoln and Ouachita Parishes in north Louisiana. This area has experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. Natural gas production in this area has increased as a result of the additional drilling, which includes deeper reservoirs in the Cotton Valley and Hosston trends.

Dubach/Lisbon/Calhoun Gathering System. The Dubach/Lisbon/Calhoun 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 it to either the Dubach or Lisbon processing plant for processing. The remainder of the raw natural gas is lean natural gas, which does not require processing and is delivered directly to interstate pipelines and our Regency Intrastate Pipeline system.


Dubach and Lisbon Processing Plant s . The Dubach processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Dubach and Calhoun gathering systems. The Lisbon plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Lisbon gathering system. These plants were acquired by us in 2003, were originally constructed in 1980 and were reassembled on their present locations in 1994 and 1996, respectively.

Elm Grove and Dubberly Refrigeration Plants. The Elm Grove and Dubberly refrigeration plants process raw natural gas located in Bossier and Webster parishes in northeastern Louisiana. Elm Grove was placed into service in May 2006 and Dubberly was placed into service in December 2006.

East Texas Region . Our east Texas gathering assets gather, compress, and dehydrate natural gas. Natural gas produced in this region contains high levels of hydrogen sulfide. Our east Texas region includes:

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the Eustace Gathering System, a large integrated natural gas gathering and processing system located in Rains, Wood, Van Zandt and Henderson Counties; and
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the Como Gathering System, a smaller integrated natural gas gathering and processing system located in Franklin, Wood, Hopkins and Rains Counties.

Both the Eustace and Como gathering systems deliver natural gas to into the Eustace processing plant that is equipped with a sulfur removal unit.

Nat ural Gas Supply. 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.

Eustac e Processing Plant. The Eustace 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 . The south Texas gathering assets gather, compress, and dehydrate natural gas. Some of the natural gas produced in this region can have significant hydrogen sulfide and carbon dioxide content. These systems are connected to processing and treating facilities that include an acid gas reinjection well. Our south Texas region primarily includes the following natural gas gathering systems:

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the LaSalle Gathering System, a large natural gas gathering system located in LaSalle and Webb counties. Gas from this system is processed by a third party.
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the Pueblo Gathering System, a large integrated natural gas gathering, treating, and processing system located in Karnes and Atascosa counties. Gas from this system is treated and processed at our Fashing Plant. We have plans to connect this system to our Tilden treating plant during 2008;
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the Tilden Gathering System, a large integrated natural gas gathering and treating system located in McMullen, Atascosa, Frio and LaSalle Counties in south Texas and flows into the Tilden treating plant; and
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the Palafox Gathering System, a small gathering system located in Dimmitt and Webb counties, Texas. The natural gas gathered by this system is delivered to a third party for processing.

Natural Gas Supply. 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.

Tilden Treating Plant. The Tilden Treating Plant is a natural gas treating plant constructed on its current location in 1981. It includes 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, recovers condensate, delivers pipeline quality gas at the plant outlet and reinjects acid gas.

West Texas Region . The system covers four Texas counties surrounding the Waha Hub, one of Texas’ major natural gas market areas. Through our Waha gathering system, we offer producers wellhead to market services. As a result of the proximity of this system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. Our west Texas region includes the Waha gathering system and the Waha processing plant.

Natural Gas Supply. The natural gas supply for the Waha gathering system is derived primarily from natural gas wells located in four counties in west Texas near the Waha Hub. Natural gas exploration and production drilling in this area has primarily targeted productive zones in the Permian Delaware basin and Devonian basin. These basins are mature basins with wells that generally have long lives and predictable flow rates.

MANAGEMENT DISCUSSION FROM LATEST 10K

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

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

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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; and

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

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

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

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

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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.
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Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component).
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Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) provisions that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, (3) fixed cash fees for ancillary services, such as gathering, treating, and compression, or (4) the ability to bypass processing in unfavorable price environments.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts. 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, crude oil, and natural gas market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

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

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

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Firm Transp ortation. 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.

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

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

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

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

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

Total Segment Margin . Segment margin from Gathering and Processing, together with segment margin from Transportation, comprise total segment margin. We use total segment margin as a measure of performance. See “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 Maintenanc e 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:

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

EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded master limited partnership. See “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. We believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe that an increase in United States natural gas production and additional sources of supply such as liquefied natural gas and other imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

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

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

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

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

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

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

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

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

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

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

RESULTS OF OPERATIONS
Year Ended December 31, 2007 vs. Year Ended December 31, 2006

Net Loss. Net loss for the year ended December 31, 2007 increased $12,384,000 compared with the year ended December 31, 2006. An increase in total segment margin of $35,490,000, 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:


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an increase in general and administrative expense of $16,717,000 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;

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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;

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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;

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an increase in depreciation and amortization of $12,085,000 primarily due to higher levels of depreciation from projects completed since December 31, 2006 and our Pueblo acquisition;

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an increase in operation and maintenance expense of $5,978,000 primarily due to increased employee related expenses, increased consumables expense, increased contractor expense and other factors discussed below; and

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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 $35,490,000 compared with the year ended December 31, 2006. This increase was attributable to an increase of $21,205,000 in gathering and processing segment margin and an increase of $14,285,000 in transportation segment margin as discussed below.

Gathering and processing segment margin increased to $132,577,000 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:

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$23,233,000 attributable to organic growth projects in the east and south Texas regions;
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$15,538,000 attributable to organic growth in the north Louisiana region; and offset by
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$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:

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$11,512,000 attributable to increased throughput volumes;
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$1,752,000 of increased margins related to our merchant function;
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$631,000 attributable to increased margins per unit of throughput; and
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$390,000 of non-cash gains from certain risk management activities.

Operation and Maintenance. Operations and maintenance expense increased to $45,474,000 in the year ended December 31, 2007 from $39,496,000 for the corresponding period in 2006, a 15 percent increase. This increase is primarily the result of the following factors:

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$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;
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$1,335,000 of increased materials and parts expense primarily in the gathering and processing segment used at our processing plants and for additional compression;
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$1,219,000 of increased consumable expenses primarily in the gathering and processing segment largely resulting from additional compression;
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$1,034,000 of increased contractor expense primarily in the gathering and processing segment associated with our Fashing processing plant;
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$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
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$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:

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$1,741,000 of insurance proceeds associated with our unplanned compressor outage in the transportation segment in 2007; and
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$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 $39,543,000 in the year ended December 31, 2007 from $22,826,000 for the same period in 2006, a 73 percent increase. The increase is primarily due to:

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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;
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$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;
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$700,000 of increased expenses associated with our long-term incentive plan that primarily relates to the issuance of restricted units, exclusive of the one-time charge discussed above; and
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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 December 31, 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 $51,739,000 in the year ended December 31, 2007 from $39,654,000 for the year ended December 31, 2006, a 30 percent increase. The increase is due to higher depreciation expense of $10,579,000 primarily from projects completed since December 31, 2006 and our Pueblo acquisition. 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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS
Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

Net income . Net income for the three months ended March 31, 2008 increased $11,643,000 compared to the three months ended March 31, 2007. An increase in total segment margin of $47,155,000 primarily attributable to our acquisitions of CDM and FrontStreet as well as organic growth in the gathering and processing segment and the absence in March 2008 of a $1,808,000 loss in March 2007 on the sale of non-core assets, was offset in part by:
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increased operation and maintenance expense of $17,920,000 primarily due to our CDM and FrontStreet acquisitions, employee related expenses and contractor expenses primarily in the gathering and processing segment;
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increased depreciation and amortization expense of $10,314,000 primarily due to our CDM, FrontStreet and Pueblo acquisitions and organic growth projects completed since March 31, 2007;
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increased general and administrative expense of $4,072,000 primarily due to our CDM acquisition and increased employee-related expenses; and
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payment, in the three months ended March 31, 2008, of a management services termination fee of $3,888,000 related to the acquisition of FrontStreet.

Segment Margin . Segment margin for the three months ended March 31, 2008 increased $47,155,000 compared with the three months ended March 31, 2007, consisting of an increase of $23,829,000 in gathering and processing segment, an increase of $380,000 in transportation segment and $23,021,000 in the contract compression segment recorded in the three months ended March 31, 2008, discussed below.

Gathering and processing segment margin increased to $54,007,000 in the three months ended March 31, 2008 from $30,178,000, an increase of $23,829,000, or 79 percent. The major components of this increase were as follows:
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$12,187,000 attributed to our FrontStreet assets;
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$9,749,000 attributed to organic growth projects, primarily in Texas;
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$3,524,000 attributed to higher throughput volumes, primarily in north Louisiana;
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$1,450,000 attributed to better pricing on commodity derivative contract settlements; and partially offset by a
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$3,082,000 decrease in non-cash valuation changes in certain commodity derivative contracts.

Transportation segment margin increased to $14,693,000 for the three months ended March 31, 2008 from $14,313,000 for the three months ended March 31, 2007, an increase of $380,000, or three percent. The major components of this increase were as follows:
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$276,000 increase due to our merchant function; and
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$104,000 increase from additional throughput volumes partially offset by slightly lower margins per unit of throughput.

Contract compression segment margin was $23,021,000 in the three months ended March 31, 2008, which consisted of $25,267,000, exclusive of $118,000 of intersegment revenue, of operating revenue and $2,364,000 of direct operating costs. The following table sets forth certain information regarding revenue generating horsepower as of March 31, 2008.

Operation and Maintenance. Operation and maintenance expense increased to $28,845,000 in the three months ended March 31, 2008 from $10,925,000 for the corresponding period in 2007, a 164 percent increase. This increase is attributable to the following factors:
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$8,844,000 related to contract compression assets acquired on January 15, 2008;
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$6,846,000 related to our FrontStreet assets;
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$977,000 increase primarily in the gathering and processing segment for the hiring of additional employees;
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$868,000 increase in contractor expense primarily in the gathering and processing segment related to assets acquired, which are operated by a third party, subsequent to March 31, 2007;
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$848,000 in various operation and maintenance expenses primarily in the gathering and processing segment associated with organic growth; and partially offset by a
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$463,000 charge to unplanned outage expense in the three months ended March 31, 2007 in the transportation segment related to the Eastside compressor fire, which represents an estimated 30-day deductible under our insurance coverage.

General and Administrative . General and administrative expense increased to $10,923,000 in the three months ended March 31, 2008 from $6,851,000 for the same period in 2007, a 59 percent increase. The increase is primarily attributable the following factors:
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$3,440,000 related to contract compression assets acquired on January 15, 2008; and
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$919,000 increase for hiring additional employees.

Other . In the three months ended March 31, 2008, we recorded a charge of $3,888,000 for the termination of long-term management services contract and transaction expenses of $348,000 in connection with our FrontStreet Acquisition. In the three months ended March 31, 2007, we sold certain non-core assets and recorded a net charge of $1,808,000.

Depreciation and Amortization . Depreciation and amortization expense increased to $21,741,000 in the three months ended March 31, 2008 from $11,427,000 for the three months ended March 31, 2007, a 90 percent increase. This increase consists of the following:
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$5,353,000 related to contract compression assets acquired on January 15, 2008;
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$2,576,000 related primarily to organic growth projects completed since March 31, 2007; and
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$2,385,000 attributed to our FrontStreet assets.

Interest Expense, Net. Interest expense, net increased $521,000, or four percent, in the three months ended March 31, 2008 compared to the same period in 2007. Of this increase, $3,895,000 was attributable to increased levels of borrowings, offset by a decrease of $3,374,000 attributable to lower interest rates.




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