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          ITEM 1.     Business.

Overview

      We are a Delaware limited partnership recently formed by HM Capital Partners LLC (formerly Hicks, Muse, Tate & Furst Incorporated), or HM Capital, to capitalize on opportunities in the midstream sector of the natural gas industry. We are a growth-oriented independent midstream energy partnership engaged in the gathering, processing, marketing and transportation of natural gas. We provide these services through systems located in north Louisiana, west Texas and the mid-continent region of the United States, which includes Kansas, Oklahoma, Colorado and the Texas Panhandle.

      We divide our operations into two business segments:

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

  •  Transportation: in which we deliver natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project.
Please refer to Notes 8 and 9 of the consolidated financial statements for information regarding revenues from external customers, segment margin, and total assets by segment.

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

      The following table contains information regarding our gathering systems and processing plants as of December 31, 2005:
                                     
                    Throughput
        Length   Wells   Compression   Capacity
Region   Asset Type   (Miles)   Connected   (Horsepower)   (MMcf/d)
                     
North Louisiana
   Gathering pipelines     600       700       14,500       300  
    Processing facilities     —       —       10,000       90  
West Texas
   Gathering pipelines     750       450       22,000       200  
    Processing facility     —       —       20,000       125  
Mid-Continent
   Gathering pipelines     1,600       1,500       41,500       265  
    Processing facility     —       —       3,650       50 (1)


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

Transportation Segment
      Our Transportation segment consists of our Regency Intrastate Pipeline system, a 320-mile natural gas pipeline in north Louisiana that transports natural gas primarily from northwest Louisiana to northeast Louisiana where it connects to a number of interstate and intrastate pipelines. Upon completion of our Regency Intrastate Enhancement Project in December 2005, our Regency Intrastate Pipeline system had a capacity of 800 MMcf/d with 27,400 horsepower of compression and a 35 MMcf/d refrigeration plant for hydrocarbon dewpoint control.

      Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. To alleviate the constraint, we constructed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. The project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project. The completion of the Regency Intrastate Enhancement Project enables us to provide transportation services from the three largest natural gas producing fields in Louisiana.

      The Regency Intrastate Enhancement Project was a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to access new sources of supply and markets. We began

planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005.

      The total cost of this project is approximately $157.0 million, and included the 40 mile expansion of our existing Regency Intrastate Pipeline system and the addition of an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system supported by approximately 9,500 horsepower of additional compression. The project has extended our transportation services into additional major producing fields in north Louisiana, connected our system to other pipelines in northeast Louisiana, and has increased the capacity of the pipeline to 800 MMcf/d.

      During the year ended December 31, 2005 (most of which preceded completion of the Regency Intrastate Enhancement Project), our Regency Intrastate Pipeline system had average throughput of 258,000 MMBtu/d.

      One of our motivations in constructing the Enhancement Project was to enable our customers to reach markets offering more favorable prices by interconnecting with other pipelines in northeast Louisiana. As of December 31, 2005, the Regency Intrastate Pipeline system could deliver gas to two 250 MMcf/d pipeline interconnects. Since then, three additional interconnects have been completed: two 250 MMcf/d pipeline interconnects and a 500 MMcf/d pipeline interconnect.

      Through March 28, 2006, we have signed definitive agreements for 466,000 MMBtu/d of firm transportation and 404,000 MMBtu/d of interruptible transportation on the Regency Intrastate Pipeline system. We are engaged in discussions with other parties interested in utilizing the remaining firm system transportation capacity.

Business Strategies

      Our management team is dedicated to increasing the amount of cash available for distribution to each outstanding unit. We intend to achieve this by pursuing organic growth projects that yield attractive returns and by capitalizing on accretive acquisition opportunities.

      Our specific strategies include:

  •  Implementing cost-effective organic growth opportunities. We intend to build natural gas gathering assets, processing facilities and transportation lines that enhance our existing systems and our ability to aggregate supply and to access premium markets for that supply. We will emphasize projects that increase volume throughput and are expected to generate attractive returns, such as our Regency Intrastate Enhancement Project and our project to provide gathering facilities for a long-term exploration and development program under an existing letter of intent with a producer in the Mid-Continent area. We are also evaluating, but have not yet made any decision to pursue, other organic growth projects. The projects under consideration include:

  •  Expansion of our Regency Intrastate Pipeline west of Haughton to relieve capacity constraints;
 
  •  extensions of the pipeline east into other fields beyond Winnsboro;
 
  •  construction and installation of a refrigeration plant at Longwood or Sibley or both;
 
  •  construction of additional compression at our Mainline Compressor Station;
 
  •  construction of a storage facility in proximity to the Regency Intrastate Pipeline in conjunction with a third party; and
 
  •  initiation and construction of step out expansion projects for our Waha gathering system.


  •  Continuing to enhance profitability of our existing assets. We intend to increase the profitability of our existing asset base by identifying new business opportunities, adding new volumes of natural gas supplies, undertaking additional initiatives to enhance utilization and continuing to reduce costs. As an example, until recently, the NGLs produced by our processing plants were sold to third parties as mixed NGLs. In September 2005, we began delivering the mixed NGLs produced by our

  processing plants to operators of fractionation facilities for fractionation for our account. We then sell the individual components, such as ethane, propane and isobutane, directly to marketing companies, refineries and other wholesalers. We believe this marketing function will allow us to earn additional margins from the sale of the NGLs that otherwise would have been earned by the fractionator.
 
  •  Pursuing accretive acquisitions of complementary assets. We intend to pursue strategic acquisitions of midstream assets in or near our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of those assets. We also intend to pursue opportunities in new regions with significant natural gas reserves and high levels of drilling activity. We believe that there will be additional acquisition opportunities as a result of the ongoing divestiture of midstream assets by large industry participants.
 
  •  Continuing to reduce our exposure to commodity price risk. Because of the volatility of natural gas and NGL prices, we attempt to operate our business in a manner that allows us to mitigate the impact of fluctuations in commodity prices and to generate stable cash flows. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. We have reduced and intend to continue to reduce, when the opportunity arises, our commodity price exposure by replacing keep-whole contracts with fee based or percentage-of-proceeds gas processing contracts. We have executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options. (Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil.) As a result, we have hedged approximately 95% of our expected exposure to NGL prices in 2006, approximately 75% in 2007 and approximately 50% in 2008. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
 
  •  Improving our credit ratings. We are committed to improving our credit ratings. The current credit ratings on our debt under our credit facilities are B+ by Standard & Poor’s and B1 by Moody’s. The additional revenue and cash flow resulting from the completed Regency Intrastate Enhancement Project will significantly improve our credit statistics that are considered by the rating agencies.

      We intend to finance our growth projects through a combination of funds available under our credit facility, commercial bank borrowings and the issuance of debt and equity securities. Given our policy of distributing available cash, we may not be able to finance such growth through the application of internal cash flow.

          Competitive Strengths

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

  •  We have a significant market presence in major natural gas supply areas. We have a significant market presence in each of our operating areas, which are located in some of the largest and most prolific gas-producing regions of the United States: the Louisiana-Mississippi-Alabama Salt basin in north Louisiana, the Delaware and Devonian basins of west Texas and the Hugoton and Anadarko basins in the mid-continent area. Our geographical diversity reduces our reliance on any particular region, basin or gathering system. Each of these producing regions is well-established with generally long-lived, predictable reserves, and our assets are strategically located in each of the regions. Currently, these areas are experiencing increased levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

  •  Our recently completed Regency Intrastate Enhancement Project will provide us with the opportunity to increase significantly our fee-based transportation throughput and cash flow. Prior to the completion of the Regency Intrastate Enhancement Project, a portion of the Regency Intrastate Pipeline system was at full capacity and was not able to capitalize on the current significant constraint on the flow of natural gas from prolific producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result of this bottleneck in the pipeline, we had not been able to increase significantly the throughput on the pipeline despite an increase in drilling and production in the area. Our Regency Intrastate Enhancement Project has substantially increased the pipeline’s capacity by alleviating the bottleneck and extending the pipeline to additional markets in northeast Louisiana. We expect this expansion project will provide us with significant additional transportation throughput volumes and stable, fee-based cash flow.
 
  •  We have the financial flexibility to pursue growth opportunities. The borrowing limit under our revolving credit facility is $160 million. At December 31, 2005 we had borrowed $50 million against this facility. This revolving credit facility provides us with the liquidity and financing flexibility we will need to execute our business strategy. We remain committed to maintaining a balanced capital structure which will afford us the financial flexibility to fund expansion projects and other attractive investment opportunities.
 
  •  We have an experienced, knowledgeable management team with a proven track record of performance. Our management team has a proven track record of enhancing value through the investment in and the acquisition, exploitation and integration of energy assets. Our senior management has an average of over 20 years of industry related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation and focus for managing and enhancing our operations for accessing strategic acquisition opportunities and for constructing new assets. Members of our senior management team have a substantial economic interest in us.
 
  •  We are affiliated with HM Capital a leading private equity investment firm headquartered in Dallas, Texas. Our affiliation with HM Capital provides us with significant benefits. We expect that our relationship with HM Capital will provide us with several significant benefits, including access to a significant pool of operational, transactional and financial professionals, multiple sources of capital and increased exposure to acquisition opportunities. HM Capital is a leading sector focused private equity firm and is currently managing and investing a $1.6 billion fund. Since the firm’s founding in 1989, HM Capital has completed more than 150 transactions in its core sectors for a total transaction value in excess of $26 billion.

          Industry Overview

      General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant located near the production, where it is treated and dehydrated and then processed through cryogenic or other processing facilities. Natural gas processing involves the separation of raw natural gas into pipeline quality natural gas, principally methane, and mixed NGLs. It also entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by interstate and intrastate pipelines to end users. Mixed NGLs that are produced by processing raw natural gas are typically transported via NGL pipelines or by truck to a fractionator, which separates the NGL into its components, such as ethane, propane, normal butane, isobutane and natural gasoline. NGLs are then sold to end users.

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

      Overview of U.S. market. The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-use markets. The midstream natural gas industry in North America includes approximately 574 processing plants that process approximately 47 Bcf of natural gas per day and produce approximately 77 million gallons per day of NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas wells.

      Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 25.9 Tcf in 2015, representing an average annual growth rate of approximately 1.7%. 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 19.8 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

      Gathering and treating. The process of raw natural gas gathering begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collect natural gas from points near producing wells and transport it to larger pipelines for further transportation. We own and operate five large gathering systems.

      Raw natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Raw natural gas produced in some areas may contain hydrogen sulfide, carbon dioxide, nitrogen and other impurities. Treating plants, such as the one that we own and operate at our Waha facility, remove these impurities before the natural gas is introduced to the processing plant. Our Waha facility utilizes an amine treating process, which involves a continuous circulation of a liquid chemical called amine that physically contacts the raw natural gas. The amine reacts with carbon dioxide and hydrogen sulfide, removing them from the gas stream prior to further processing.

      Compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production in the ground against a higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market.

Field compression is typically used to lower the entry pressure, while maintaining or increasing the exit pressure of a gathering system to allow it to operate at a lower receipt pressure and provide sufficient pressure to deliver gas into a higher downstream pipeline.

      Processing. Raw natural gas produced at the wellhead is often unsuitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. The principal components of raw natural gas are methane and ethane, but most raw natural gas also contains varying amounts of NGLs (such as ethane, propane, normal butane, isobutane, and natural gasoline) and impurities, such as water, sulfur compounds, carbon dioxide, or nitrogen. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other impurities reduced to very low concentrations. Raw natural gas is processed not only to remove unwanted impurities that would interfere with pipeline transportation or use of raw natural gas, but also to separate from the gas those hydrocarbon liquids that have higher financial value as NGLs. We own and operate four cryogenic natural gas processing plants. The cryogenic process utilizes heat exchangers and a turbo-expander to cool the gas and condense the NGLs. The NGLs are then separated from the gaseous components.

      Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. We do not own or operate any NGL fractionation facilities. We ship the NGLs that we produce to a fractionator. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient in synthetic rubber), 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.

      Marketing. Natural gas and NGL marketing involves the sale of the pipeline-quality gas and NGLs that are either produced by processing plants or purchased from gathering systems or other pipelines. In the fall of 2005, we began marketing NGLs for our account and for the accounts of our customers.

      Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines. We own and operate the Regency Intrastate Pipeline system, an intrastate natural gas pipeline system located in north Louisiana. Our intrastate natural gas pipeline system includes a refrigeration processing plant that is utilized to reduce the hydrocarbon dewpoint of natural gas in order to meet downstream market pipeline-quality specifications.

          Gathering and Processing Operations

General
      We contract with producers to gather raw natural gas from individual wells or central delivery points located near our processing plants or gathering systems. In general, once we have executed a contract, we connect wells and central delivery points to our gathering lines through which the raw natural gas is delivered to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At our processing plants, we remove any impurities in the raw natural gas stream, process the gas and extract the NGLs.

      We continuously seek new sources of raw natural gas supply to increase throughput volume on our systems and through our plants. We connected 44 new wells in 2004 and 117 new wells during 2005, including connections of central delivery points which may have multiple wells behind them.

      All raw natural gas flowing through our gathering and processing facilities is supplied under gathering and processing contracts having fixed terms ranging from month-to -month to 20 years. Alternatively, we

have some contracts that span the life of the oil and gas lease. For a description of our contracts, please read “Our Contracts” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

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

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

      Our natural gas gathering and processing assets consist primarily of five large natural gas gathering systems and four active cryogenic gas processing plants which are located in north Louisiana, West Texas and the mid-continent region of the United States. The following table contains certain information regarding these gathering systems and processing plants as of and for the year ended December 31, 2005:
                                   
                Throughput
    Length   Wells   Compression   Capacity
Asset   (Miles)   Connected   (Horsepower)   (MMcf/d)
                 
North Louisiana
                                
 
Dubach/Calhoun/Lisbon Gathering System
     600       700       14,500       300  
 
Dubach Processing Plant
     —       —       7,000       50  
 
Lisbon Processing Plant
     —       —       3,000       40  
West Texas
                                
 
Waha Gathering System
     750       450       22,000       200  
 
Waha Processing Plant
     —       —       20,000       125  
Mid-Continent
                                
 
Hugoton Gathering System
     850       900       28,000       120  
 
Mocane-Laverne Gathering System
     500       350       4,000       100  
 
Greenwood Gathering System
     250       250       9,500       45  
 
Mocane Processing Plant
     —       —       3,650       50  


North Louisiana System
      Our north Louisiana system includes the Dubach and Lisbon processing plants and the Dubach/ Calhoun/ Lisbon gathering system, which is a large integrated natural gas gathering and processing system located primarily in four parishes of north Louisiana and includes over 600 miles of gathering pipelines.

      The following is a map of our north Louisiana gathering and processing system.

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

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

      During the year ended December 31, 2005, we connected 62 wells to our north Louisiana gathering system.

      Devon Energy Corporation and XTO Energy Inc. represented approximately 21% and 13%, respectively, of our natural gas supply in this region for the year ended December 31, 2005.

      Dubach/ Lisbon/ Calhoun Gathering System. The Dubach/ Lisbon/ Calhoun gathering system consists of over 600 miles of natural gas gathering pipelines ranging in size from two inches in diameter to ten inches in diameter. The system gathers raw natural gas from producers and delivers approximately 85% of the raw natural gas to either the Dubach or Lisbon processing plants for processing. The remainder of the raw natural gas is lean natural gas, which does not require processing and is delivered directly to interstate pipelines and our Regency Intrastate Pipeline system.

      Dubach Processing Plant. The Dubach processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Dubach and Calhoun gathering systems and natural gas transported on the Regency Intrastate Pipeline system. This plant, which was acquired by us in 2003, was originally constructed in 1980 and was subsequently reassembled in its present location in 1994.

      Lisbon Processing Plant. The Lisbon processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Lisbon gathering system. This plant, which was acquired by us in 2003, was constructed in 1980 and was subsequently reassembled in its present location in 1996.

      Markets. There are numerous market outlets for the raw natural gas that we gather and the NGLs that we produce on our north Louisiana systems. The Dubach/ Lisbon/ Calhoun gathering system is directly connected to several interstate natural gas pipelines, including Texas Gas Transmission, Mississippi River Transmission and Texas Eastern Transmission, and to our Regency Intrastate Pipeline system. Our access to numerous markets, including interstate pipelines in northeast Louisiana and to several power plants located on our system, provides us with the flexibility to sell our natural gas supply into markets with the most attractive pricing.

      The NGLs extracted from the raw natural gas at our processing plants are transported by a 37-mile Regency NGL pipeline to a third-party pipeline that delivers the NGLs to Mont Belvieu, Texas for fractionation by third parties.

      Our primary purchasers of pipeline-quality gas on the north Louisiana gathering system are Atmos Energy Marketing, LLC, Duke Energy Field Services and Sequent, which represented approximately 64%, 11% and 10%, respectively, of the revenues from such sales for the year ended December 31, 2005. All of the NGL sales from the north Louisiana processing plants were made to Koch Hydrocarbon, LP, which provided fractionation services during this period.

West Texas System
      The following is a map of our Waha gathering and processing system.

      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.

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

      This area is experiencing increasing levels of oil and natural gas drilling activity as a result of strong demand for natural gas and recent discoveries. In addition, several independent exploration and production companies are pursuing more aggressive drilling programs than the major oil companies that currently are the primary producers in the area. Several of these independent exploration and production companies are developing unexploited reserves within our area of operations through new well completions and infill drilling, along with workovers and re-completions of existing wells. Additionally, there have been recent large oil and natural gas discoveries in this region by Chesapeake Energy Corporation and Anadarko Petroleum Company. We believe that our significant presence and modern and efficient asset base provides us with competitive advantages in capturing new supplies of natural gas in the region. Many of these areas of increased drilling require little to no pipeline or meter expense as producers are connecting to existing facilities.

      During the year ended December 31, 2005, we connected to 24 wells to our Waha gathering system.

      Duke Energy Field Services and ExxonMobil Corporation represented approximately 25% and 14%, respectively, of our natural gas supply in this region for the year ended December 31, 2005.

      Waha Gathering System. The Waha gathering system consists of approximately 750 miles of natural gas gathering pipelines ranging in size from three inches in diameter to 24 inches in diameter. We offer producers four different levels of natural gas compression on the Waha gathering system, as compared to the two levels typically offered in the industry. By offering multiple levels of compression, our gathering system is often more cost-effective for our producers, since the producer is not required to pay for a level of compression that is higher than the level it requires.

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

      Markets. The Waha gathering system has a variety of market outlets for the natural gas that we gather. The pipeline-quality gas from our gathering and processing operations can be delivered into the Waha Hub, which includes connections to several major interstate and intrastate pipelines serving California, the mid-continent and Texas natural gas markets, including Oasis Pipeline, Enterprise Texas Pipeline, Atmos Pipeline, ONEOK Westex and El Paso Natural Gas Pipeline. The NGLs extracted from the raw natural gas at the Waha processing plant are transported to ExxonMobil’s NGL pipeline, which delivers the NGLs to facilities in Mont Belvieu, Texas for fractionation by third parties.

      Our primary purchasers of pipeline-quality gas on the west Texas gathering system are Energy Transfer Partners, Tenaska Marketing Ventures, and BP Energy Company, which represented approximately 40%, 25% and 15%, respectively, of the revenues from such sales for the year ended December 31,

2005. All of the NGL sales from the Waha processing plant were made to ExxonMobil Corporation, which fractionated the NGLs from these plants during this period.

Mid-Continent Systems
      Our mid-continent systems include the following natural gas gathering systems primarily in Kansas and Oklahoma:

  •  the Hugoton gathering system, which is a large integrated natural gas gathering and processing system located in southwestern Kansas and includes approximately 850 miles of gathering pipeline;
 
  •  the Mocane-Laverne gathering system, which is a large integrated natural gas gathering and processing system located primarily in the Oklahoma Panhandle and includes approximately 500 miles of gathering pipelines and the Mocane cryogenic processing plant; and
 
  •  the Greenwood gathering system, which is a large natural gas gathering system located primarily in southwestern Kansas and includes approximately 250 miles of gathering pipelines.

      Our mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas from approximately 1,500 wells. These systems are geographically concentrated, with each central facility located within 90 miles of the others. We operate our mid-continent gathering systems at low pressures to increase the total throughput from the connected wells. Wellhead pressures are therefore adequate to access the gathering lines without the cost of wellhead compression. In addition, we process natural gas from the Mocane-Laverne gathering system at our Mocane processing plant.

      The following is a map of our mid-continent gathering and processing systems.

      Natural Gas Supply. Our mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, including the Hugoton Basin in southwest Kansas and the Anadarko Basin in western Oklahoma and the Texas panhandle. These mature basins have continued to provide generally long-lived, predictable reserves. Recent increases in production in these areas have been driven primarily by continued infill drilling, compression enhancements, and advanced well bore

completion technology. In addition, the application of 3-D seismic technology in these areas has yielded better-defined reservoirs for continuing development of these basins.

      During the year ended December 31, 2005, we connected 31 wells to our mid-continent gathering systems.

      Occidental Petroleum Corporation and Penn Virginia Corporation provided approximately 21% and 10%, respectively, of our natural gas supply in this region for the year ended December 31, 2005.

      Hugoton Gathering System. The Hugoton gathering system is located in southwestern Kansas. It consists of approximately 850 miles of natural gas gathering pipelines ranging in size from two inches in diameter to 20 inches in diameter. Substantially all of the raw natural gas gathered by the Hugoton gathering system is delivered to a third party’s processing plant. We pay the third party a fee to process the gas for our account.

      Mocane-Laverne Gathering System. The Mocane-Laverne gathering system is located in Beaver and Harper counties in the Oklahoma panhandle and Meade County in southwestern Kansas. It consists of approximately 500 miles of natural gas gathering pipelines ranging in size from two inches in diameter to 24 inches in diameter. The system gathers raw natural gas from producers and delivers it for processing to the Mocane processing plant.

      Mocane Processing Plant. The Mocane processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Mocane-Laverne gathering system. This plant was constructed in 1975 and acquired by us in 2003.

      Greenwood Gathering System. The Greenwood gathering system is located in Morton and Stanton Counties in southwestern Kansas and Baca County in southeastern Colorado. It consists of approximately 250 miles of natural gas gathering pipelines ranging in size from four inches in diameter to 20 inches in diameter. The raw natural gas gathered by this system is delivered to a third party’s processing plant. We pay the third party a fee to process the gas for our account.

      Markets. The pipeline-quality gas from our gathering and processing operations in the mid-continent area is delivered primarily into Panhandle Eastern Pipeline to serve markets in the mid-continent and upper Midwest. This gas can also be sold into the ANR Pipeline via the North Kiowa system or via the CIG Pipeline or can be pooled through BP’s Jayhawk processing plant and Pioneer Natural Resources’ Santanta processing plant.

      The NGLs extracted from the raw natural gas at our gathering and processing plants are transported by a third party NGL pipeline that delivers the NGLs to the Conway Hub in Kansas for fractionation by a third party.

      Our primary purchasers of pipeline-quality gas on the mid-continent gathering systems are Seminole Energy Services, LLC, BP Energy Company, and Cinergy Marketing and Trading, LP, which represented 37%, 29% and 21%, respectively, of the revenues from such sales for the year ended December 31, 2005. All of the NGL sales from the mid-continent processing plants were made to Koch Hydrocarbon, LP, which fractionated these NGLs during this period.

Other Processing Systems
      We also own the Lakin processing plant, which is a cryogenic processing plant with nitrogen rejection and helium recovery capabilities. This plant has a capacity of 80,000 Mcf/d. The plant was constructed in 1995 and was acquired by us in 2003. Through July 31, 2005, the Lakin processing plant processed raw natural gas received from the Hugoton gathering system. As part of our previously planned strategy, we suspended operations at the Lakin processing plant (subject to intermittent resumption) as of August 1, 2005. Suspending the operations of the plant allowed us to renegotiate certain unfavorable keep-whole processing contracts covering gas processed at the plant and replace them with fee-based contracts and to avoid charges for transporting natural gas from the Hugoton gathering system through a third party pipeline out of the tailgate of the Lakin plant. All of the gas from the Hugoton gathering system is now

processed at a third party processing plant for our account for a fee. We are currently evaluating opportunities to utilize the Lakin processing plant, which may include connecting a new source of supply to the plant or moving the plant to another area.

Transportation Operations

      General. We own and operate a 320-mile intrastate natural gas pipeline system, known as the Regency Intrastate Pipeline system, in north Louisiana extending from northwest Louisiana to northeast Louisiana. This system includes 27,400 horsepower of compression and a 35 MMcf/d refrigeration plant for hydrocarbon dewpoint control. The following map presents the location of the Regency Intrastate Pipeline system, including the Regency Intrastate Enhancement Project described below:

      The following table contains certain information regarding the Regency Intrastate Pipeline system prior to the commencement of construction and following the completion of the Regency Intrastate Enhancement Project:
                                   
            Throughput    
    Length   Compression   Capacity   Market
Asset   (Miles)   (Horsepower)   (MMcf/d)   Outlets
                 
Regency Intrastate Pipeline System
                                
 
Pre-Enhancement Project
     200       17,900       200       6  
 
Post-Enhancement Project
     320       27,400       800       11  
Haughton Refrigeration Processing Plant
     —       —       35       —  

      During the years ended December 31, 2005 and 2004, the Regency Intrastate Pipeline system had average throughput of 258,194 MMBtu/d and 189,640 MMBtu/d, respectively. Natural gas generally flows from west to east on the pipeline from wellhead connections or connections with other gathering systems.

      Prior to the completion of our Regency Intrastate Enhancement Project, our Regency Intrastate Pipeline system consisted of the following components:

      •     the Elm Grove System, a 31-mile, 12-inch diameter pipeline placed in operation in 1974 that extends from Southwestern Electric Power Company’s Arsenal Hill Power Plant in Caddo Parrish eastward to the Elm Grove natural gas field in Bossier Parish;

      •     the North Louisiana Pipeline, a 23-mile, 12-inch diameter pipeline and a 25-mile, 16-inch diameter pipeline placed in service in 1989 that extends from the tie-in point with the Elm Grove System to an interconnection with a pipeline owned by Southern Natural Gas Company in Bienville Parish;

      •     the Metco Pipeline, a 19-mile, 20-inch diameter pipeline placed in operation in 1990 that extends from the interconnect point with the pipeline owned by Gulf States Transmission Corporation to the western end of the Elm Grove System interconnect;

      •     the Ruston System, a 12-mile, six-inch diameter pipeline, a six-mile, 12-inch diameter pipeline and a 0.5-mile, four-inch diameter pipeline located in Jackson and Lincoln Parishes in northeast Louisiana and interconnects with pipelines owned by Southern Natural Gas Co. and Duke Energy Field Services;

      •     the Panda Pipeline, a 20-mile, 20-inch diameter pipeline and an 11-mile, 24-inch diameter pipeline placed in operation in 2002 that extends from the eastern portion of the North Louisiana Pipeline to an interstate pipeline that transports natural gas exclusively to a power generation plant; and

      •     the Dubach Extension, an eight-mile, 12-inch diameter pipeline that was constructed as part of our Enhancement Project and is described in further detail below.

      Our Regency Intrastate Pipeline system includes a natural gas refrigeration conditioning plant. At the plant, we condition natural gas to remove NGLs to ensure that it meets pipeline-quality specifications so that it can be transported on our intrastate pipeline. The NGLs extracted from the raw natural gas at our refrigeration conditioning plant are sold to a third party at the tailgate of the plant.

      Our primary purchasers of pipeline-quality gas on the Regency Intrastate Pipeline system are Alabama Gas Corporation, Southwestern Power and Electric Company and Louis Dreyfus Energy, which represented approximately 66%, 9% and 9%, respectively, of the external revenues from such sales for the year ended December 31, 2005.

      Enhancement Project. Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. As a result, in 2005, we undertook to construct and completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. The project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.

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

      The total cost of this project is approximately $157.0 million. On July 1, 2005, we completed the Dubach extension, which consists of an eight mile, 12-inch diameter pipeline and connection to the Panda Pipeline to our Dubach processing plant located on our north Louisiana gathering system. The Dubach extension provides the Regency Intrastate Pipeline system with direct access to four interstate pipelines that are directly connected to the Dubach processing plant.

      As of October 1, 2005, we had completed construction of the second phase of this project, a 40-mile, 24-inch diameter system loop along a portion of our existing pipeline. This additional pipeline increased the capacity of the Regency Intrastate Pipeline system by 100 MMcf/d.

      In December 2005, we completed construction of the final phase of this project, which includes an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system providing transportation services from several major producing fields in north Louisiana to markets in northeast Louisiana. This Winnsboro extension extends from the eastern terminus of the North Louisiana Pipeline to a point near Winnsboro, Louisiana.

      In order to facilitate the enhancement of the system, we also added approximately 9,500 horsepower of compression.

      As a result of the completion of the Regency Intrastate Enhancement Project, we are able to transport natural gas produced from the Vernon field, the Elm Grove field and the Sligo field, which are the three largest natural gas producing fields in Louisiana.

      New Transportation Contracts. Through March 28, 2006, we have signed definitive agreements for 466,000 MMBtu/d of firm transportation and 404,000 MMBtu/d of interruptible transportation on the Regency Intrastate Pipeline system. We are engaged in discussions with other parties interested in utilizing the remaining firm system transportation capacity.

      Funding of Project Costs. In July 2005, we amended our credit facilities to provide for $170 million in additional borrowing capacity, consisting of $60 million in additional term loans and $110 million in additional revolving loans. We used these amounts, together with an additional $15 million equity contribution from funds managed by HM Capital Partners and other investors, including directors and members of management (collectively, the HM Capital Investors) to complete the Regency Intrastate Enhancement Project. For information regarding the terms of the amended and restated credit facilities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements.”

      Interstate Pipeline Specifications. The markets to which the shippers on our Regency Intrastate Pipeline ship natural gas include interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include such matters as hydrocarbon dewpoint, temperature and impurities including water, sulphur, carbon dioxide and hydrogen sulphide. These specifications vary by interstate pipeline. If the total mix of natural gas shipped by the shippers on our pipeline fails to meet the specifications of a particular interstate pipeline, that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it.

      In certain cases, the mix of natural gas that we transport for shippers on our Regency Intrastate Pipeline does not meet the dewpoint specification of one of our interconnected interstate pipelines. In October 2005, we began construction of a refrigeration plant at Elm Grove to remove hydrocarbons and allow the natural gas to meet these dewpoint specifications. We expect the plant to be completed by the end of April 2006.

      An interstate pipeline curtailed shipments through its existing interconnect with our pipeline in late November 2005. We and our shippers have thus far been able to find alternative markets for all the curtailed gas. If for some reason we are unable to do so during the period prior to completion of the Elm Grove refrigeration plant, we may be required to shut-in non-conforming gas delivered to us for transportation. We estimate that a reduction of approximately 25,000 MMBtu/d would substantially restore the total mix of transported gas to these dewpoint specifications.

      Also, lean or processed gas that we transport or are scheduled to transport may be mixed with gas that does not meet dewpoint specifications, which lowers the overall dewpoint of the natural gas stream and allows us to avoid having to shut-in any gas. As a result of the introduction of a significant quantity of lean gas into the system following the completion of the Regency Intrastate Enhancement Project, the interstate pipeline has suspended its curtailments.

Other Assets

      Gulf States Transmission, our small interstate pipeline, consists of approximately 10 miles of 20-inch pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. The pipeline has a Federal Energy Regulatory Commission (FERC) certificated capacity of 150 MMcf/d.

Our Contracts

      Gathering and Processing Contracts. We contract with producers to gather raw natural gas from individual wells or central delivery points located near our gathering systems and processing plants. Once we have executed a contract with the producer, we connect the producer’s wells and central delivery points to our gathering lines through which the natural gas is delivered to a processing plant (whether owned and operated by us or a third party) for a fee. We obtain supplies of raw natural gas for our gathering and processing facilities under contracts having terms ranging from month-to -month to twenty years or life of the lease. We categorize our processing contracts in increasing order of commodity price risk as fee-based, percentage-of -proceeds, or keep-whole contracts. Additionally, it is common for a percentage-of -proceeds or keep-whole contract to have a fee component in addition to its commodity-sensitive component. For a description of our fee-based arrangements, percent-of -proceeds arrangements, and keep-whole arrangements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

      At December 31, 2005, the mixture of our gathering and processing contracts by category and by geographic region is set forth in the following table:
                           
    Nature of Contract
    (Measured by 2005 volumes)
     
    Keep-Whole   POP   Fee-Based
Geographic Region            
North Louisiana(1)
     29.3 %     57.9 %     12.8 %
West Texas
     18.0 %     44.5 %     37.5 %
Mid-Continent
     31.3 %     46.8 %     21.9 %
 
 
Total Gathering and Processing
     26.1 %     48.5 %     25.4 %


Note (1) — approximately 24% of 29% reported keep-whole exposure in north Louisiana is attributable to a package of bypassable gas controlled by us. We only process this gas when economically beneficial.
      Fee Transportation Contracts. We provide natural gas transportation services on the Regency Intrastate Pipeline pursuant to contracts with natural gas shippers. These contracts are all fee-based. Generally, our transportation services are of two types: firm transportation and interruptible transportation. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the capacity is utilized by the shipper, and in some cases the shipper also pays a commodity charge with respect to quantities actually shipped. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped. We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with FERC with respect to transportation authorized under section 311 of the Natural Gas Policy Act.

      Merchant Transportation Contracts. We perform a limited merchant function on our Regency Intrastate Pipeline system. We purchase natural gas from 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 at which we sell the natural gas at market price. We regard the total 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 same index price on the date of settlement.

Competition

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

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

  •  North Louisiana: CenterPoint Energy Gas Marketing Company; Gulf South Pipeline L.P.; PanEnergy Louisiana Intrastate, LLC (Pelico).
 
  •  West Texas: Sid Richardson Energy Services Co.
 
  •  Mid-Continent: Duke Energy Field Service, L.P.; ONEOK Energy Marketing and Trading, L.P.; Penn Virginia Corporation.

      In transporting natural gas across north Louisiana, we face major competition from CenterPoint Energy Gas Marketing Company, Gulf South Pipeline, L.P., and Texas Gas Transmission, LLC. Many of our competitors have substantially greater resources, both in capital and in access to shippers’ supplies of natural gas than we do. Competition in natural gas transportation is characterized by price of transportation, the nature of the markets accessible from a transportation pipeline and nature of service.

Risk Management

      To manage commodity price risk, we have implemented a risk management program under which we seek to match sales prices of commodities (especially natural gas) with purchases under our contracts; manage our portfolio of contracts to reduce commodity price risk; optimize our portfolio by active monitoring of basis, swing, and fractionation spread exposure; and hedge a portion of our exposure to commodity prices (specifically NGLs).

      To the extent that we purchase or commit contractually to purchase natural gas that we gather and process, we are exposed to commodity price changes in both the natural gas and NGL markets. Operationally, we mitigate this price risk by generally purchasing natural gas and NGLs at prices derived from published indices, rather than at a contractually fixed price and by marketing natural gas and natural gas liquids under similar pricing mechanisms. In addition, we optimize the operations of our processing facilities on a daily basis, for example by rejecting ethane when recovery of ethane as an NGL is uneconomical.

      As a consequence of our processing contract portfolio, we derive a portion of our earnings from a long position in NGL products, resulting from the purchase of natural gas for our account or from the payment of processing charges in kind, that are exposed to commodity price fluctuations. Shortly after the acquisition of our company by HM Capital, we implemented a policy of hedging this commodity price risk by purchasing a series of contracts relating to swaps of individual NGL products and crude oil puts. Our hedging position and needs to supplement or modify our position are closely monitored by the Risk Management Committee of our Managing General Partner. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk” for information regarding the status of these contracts and the accounting treatment to be accorded to them. As a matter of policy we do not acquire forward contracts or derivative products for the purpose of speculating on price changes.

Regulation

      Intrastate Pipeline Regulation. To the extent that our Regency Intrastate Pipeline system transports natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to the jurisdiction of FERC, under Section 311 of the Natural Gas Policy Act of 1978, or NGPA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of “fair and equitable” rates are subject to refund with interest. NGPA Section 311 rates deemed fair and equitable by FERC are generally analogous to the cost-based rates that FERC deems “just and reasonable” for interstate pipelines under the Natural Gas Act, or NGA. Certain aspects of FERC rate regulation under the NGA are discussed under the section below entitled “Regulation  — Interstate Pipeline Regulation.” Additionally, the terms and conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval.

      FERC Pipeline Regulation. Regency Intrastate Gas LLC, or RIGS, is one of our subsidiaries which transports interstate gas in Louisiana under Section 311 (a) (2) of the NGPA for many of its shippers. FERC approves Section 311 (a)(2) transportation rates for our intrastate pipeline (as for others) typically on a cost of service basis. FERC requires most of these pipelines, including RIGS, to file triennial rate petitions either justifying its existing rates or requesting new rates. RIGS’ most recent Section 311 maximum rates were established by a FERC order dated September 26, 2005, and were set for firm transportation at $0.15 per MMBtu/d reservation charge, with a $0.05 MMBtu commodity charge, and for interruptible transportation at $0.20 per MMBtu/d. RIGS is obligated to file its next Section 311 rate case no later than May 1, 2008.

      Under Section 311, intrastate pipelines providing transportation service under NGPA Section 311 may avoid jurisdiction that would otherwise apply under the Natural Gas Act of 1938, or NGA.

      Any failure on our part:

  •  To observe the service limitations applicable to transportation service under Section 311,
 
  •  to comply with the rates approved by FERC for Section 311 service,
 
  •  to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or
 
  •  to comply with applicable FERC regulations, the NGPA or certain state laws and regulations

could result in an alteration of our jurisdictional status or the imposition of administrative, civil and criminal penalties, or both.

      Our Regency Intrastate Pipeline system in north Louisiana is subject to regulation by various agencies of the State of Louisiana. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. Louisiana also has agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.

      Interstate Pipeline Regulation. FERC also has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the Gulf States Transmission Corporation pipeline. Under the Natural Gas Act, rates charged for interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates are subject to refund with interest. Gulf States Transmission holds a FERC-approved tariff setting forth cost-based rates, terms and

conditions for services to shippers wishing to take interstate transportation service. FERC’s authority extends to:

  •  rates and charges for natural gas transportation and related services;
 
  •  certification and construction of new facilities:
 
  •  extension or abandonment of services and facilities;
 
  •  maintenance of accounts and records;
 
  •  relationships between the pipeline and its energy affiliates;
 
  •  terms and conditions of service;
 
  •  depreciation and amortization policies;
 
  •  accounting rates for ratemaking purposes;
 
  •  acquisition and disposition of facilities;
 
  •  initiation and discontinuation of services; and
 
  •  information posting requirements.

      FERC regulation and policy determine whether and to what extent an interstate pipeline’s costs are eligible for inclusion in that pipeline’s cost-of -service for purposes of establishing the pipeline’s maximum “just and reasonable” rates for service. Under new FERC rate policy, pipelines are permitted to include, as part of their cost-of -service, a full income tax allowance for all entities owning the public utility asset, provided that such entities or individuals are subject to an actual or potential tax liability to be paid on income derived from the public utility asset. FERC’s income tax allowance policy is, however, currently being challenged, and may be subject to change in the future. As a consequence, we cannot provide any assurance that we will be able to continue to include an income tax allowance in the cost-of -service used to set Gulf States Transmission Corporation’s maximum just and reasonable rates. Additionally, whether and to what extent an intrastate pipeline company providing service under NGPA Section 311 is allowed to include an analogous income tax allowance in its cost-of -service for ratemaking purposes is currently unclear and is, in any event, likewise subject to change in the future.

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

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

      Natural gas gathering may receive greater regulatory scrutiny at both the state and the federal levels now that FERC has taken a less stringent approach to regulation of the gas gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the Texas Railroad Commission, or TRRC, has approved

changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. In addition, many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters 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.

      Sales of Natural Gas. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The prices at which we sell natural gas are affected by many competitive factors, including the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting interstate transportation, including interstate natural gas pipelines and natural gas storage facilities. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas companies with whom we compete.

      Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and NGLs are not currently regulated. Prices of these products are set by the market rather than by regulation. Effective as of January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil, NGLs and other products that allowed for an increase in the cost of transporting oil to the purchaser. The implementation of these regulations has not had a material adverse effect on our results of operations.

Environmental Matters

      General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to the release of hazardous substances or wastes into the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing and operating our plants, pipelines and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with the environmental laws.

      Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil or criminal penalties, requirements to perform investigatory or remedial activities and the issuance of injunctions or construction bans or delays. We have implemented procedures to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our consolidated results of operations or financial condition.

      Under an omnibus agreement, Regency Acquisition LP agreed to indemnify us in an aggregate amount not to exceed $8.6 million generally for three years after February 3, 2006 for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and

occurring or existing before that date. For a discussion of the omnibus agreement, please read Item 13 “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

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

      We also generate both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA and comparable state statutes. From time to time, the EPA has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. It is possible, however, that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.

      We currently own or lease properties that have been used over the years by prior owners and by us for natural gas gathering, processing and transportation. Solid waste disposal practices within the midstream gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of or released on or under various properties during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these dispositions of wastes may have occurred during the ownership of these assets by others, these properties and wastes may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial operations to prevent the migration of contamination.

      It is this possibility that led the management of Regency Gas Services to negotiate for the inclusion of environmental indemnity provisions in the agreement under which it agreed to acquire assets from El Paso Field Services LP and its affiliates in 2003. Those provisions included an indemnity of Regency Gas Services by the El Paso sellers against a variety of environmental claims for a period of five years up to an aggregate of $84 million. They also included an escrow of $9 million relating to claims, including environmental claims, under the El Paso agreement.

      Regency Gas Services has submitted a claim against the El Paso sellers for a variety of environmental defects at these assets, and the El Paso sellers have agreed to maintain $5.4 million in the escrow account to pay any claim amounts for environmental matters ultimately deemed to be covered by their indemnity. This amount represents the upper end of the estimated remediation cost calculated by Regency based on the results of its investigations of these assets.

      A Phase I environmental study was performed on our west Texas assets by an environmental consultant engaged by us in connection with our investigation of those assets prior to our purchase of them in 2004. The study indicated that most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote.

      At the time of the negotiation of the agreement to acquire the west Texas assets in the first quarter of 2004, management of Regency Gas Services obtained an insurance policy against specified risks of environmental claims up to $10 million. The premiums on the insurance policy were prepaid for a period of 10 years or until February 2014. This policy covers third party claims for on-site and off-site cleanup costs and personal injury/property damage arising from pre-February 2004 contamination or incidents, with a $100,000 per claim deductible.

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

      ODEQ Notice of Violation. In March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent us a notice of violation, alleging that we are operating the Mocane processing plant in Beaver County, Oklahoma in violation of the National Emission Standard for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities, or NESHAP, and the requirements to apply for and obtain a federal operating permit (Title V permit). After seeking and obtaining advice from the Environmental Protection Agency, the ODEQ issued an order requiring us to apply for a Title V permit with respect to emissions from the Mocane processing plant by April 2006. No fine or penalty was imposed by the ODEQ. While we believe that the basis for the allegations identified in the notice of violation is inapplicable to the Mocane processing plant, we intend to comply with the order. Resolution of this matter will not have any materially adverse effect on our consolidated results of operations.

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

      Absent the physical or operational changes at the Waha processing plant that allegedly occasioned the NOE, the air emissions at the plant would have been limited, based on the plant’s “grandfathered” status under the relevant federal statutory standards, only by historical amounts until 2007. In anticipation of the expiration of that status and regardless of the outcome of the NOE, we submitted to the TCEQ in early February 2005 an application for a state air permit for emissions from the Waha plant predicated on the

construction of an acid gas reinjection well and, after completion of the well and facilities, the reinjection of the emitted gases. That permit has been issued and requires completion of construction of the well and facilities by the end of February 2007. We estimate the capital expenditure relating to the well and facilities at $6.0 million.

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

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

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

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

      Our intrastate pipeline facilities are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers natural gas, crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, we cannot predict the effect of any new or amended laws and regulations or reinterpretation of existing laws and regulations on our future compliance with the NGPSA.

      Louisiana administers federal pipeline safety standards under the NGPSA. The Louisiana Office of Conservation, Pipeline Division, monitors Louisiana intrastate pipeline operators to ensure safety and compliance with regulations. Among other things, the Louisiana Office of Conservation conducts pipeline inspections and accident investigations, and it oversees compliance and enforcement, safety programs, and

record maintenance and reporting. The “rural gathering exemption” under the NGPSA currently exempts our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future, and that exemption does not apply to our intrastate natural gas pipeline facilities. With respect to recent pipeline accidents in other parts of the country, Congress and the DOT have passed or are considering heightened pipeline safety requirements.

Employees

      Our Managing GP or its affiliates employ approximately 153 employees, of whom 103 are field operating employees and 50 are mid- and senior-level management and staff.

      None of these employees is represented by a labor union and there are no outstanding collective bargaining agreements to which our Managing GP or any of its affiliates is a party. Our Managing GP believes that it has good relations with its employees.

Legal Proceedings

      We are not a party to any material litigation. See, however, the discussion of the TCEQ NOE and the ODEQ NOV under “— Environmental Matters — TCEQ Notice of Enforcement” and “— Environmental Matters — ODEQ Notice of Violation.” Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.

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

Available Information

      Regency Energy Partners LP files annual and quarterly financial 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 .

      The Partnership makes its SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through its Internet site located at http://www.regencyenergy.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.

          ITEM 1A.     Risk Factors.

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

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

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner.
      We may not have sufficient available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

  • the fees we charge and the margins we realize for our services and sales;
 
  • the prices of, level of production of, and demand for natural gas and NGLs;
 
  • the volumes of natural gas we gather, process and transport;


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

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

  • our debt service requirements;
 
  • fluctuations in our working capital needs;
 
  • our ability to borrow funds and access capital markets;
 
  • restrictions contained in our debt agreements;


        •     the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;

  • 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 on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

If we do not receive the revenues we anticipate from the Regency Intrastate Enhancement Project, our cash flow and our ability to make cash distributions to you may be adversely affected.
      Our ability to pay the minimum quarterly distributions for 2006 assumes, among other things, the generation of revenues contemplated by the gas transportation contracts relating to our Regency Intrastate Enhancement Project.

      Our ability to pay the minimum quarterly distributions for 2006 also assumes the generation of the revenues contemplated by the contracts that we have entered into with our customers relating to the transportation of gas on our Regency Intrastate Pipeline. If any of the following were to occur, our forecast of these revenues would be adversely affected:

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

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

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

While substantial amounts of the incremental capacity resulting from the completion of the Regency Intrastate Enhancement Project has been contracted, if we are unable to utilize the remaining incremental transportation capacity, our business and our operating results could be adversely affected.
      We have agreed to provide natural gas transportation services to natural gas producers in the area upon completion of the Regency Intrastate Enhancement Project, which increased our capacity on the Regency Intrastate Pipeline from 200 MMcf/d to 800 MMcf/d. We have signed definitive agreements for 466,000 MMbtu/d of firm transportation and for 404,000 MMbtu/d of interruptible transportation. We are currently transporting approximately 450,000 MMbtu/d under these existing contracts. We are engaged in discussions with various shippers interested in contracting for portions of the uncommitted capacity on the system for firm transportation of natural gas volumes. If we are unable to commit the remaining uncommitted capacity on the system to firm gas transportation contracts and the parties to existing interruptible transportation contracts fail to utilize the capacity, our business and our operating results could be adversely affected.

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

      The level of natural gas drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. Currently, natural gas prices are high in relation to historical prices. For example, the twelve-month average of NYMEX daily settlement price of natural gas increased from $6.18 per MMBtu as of December 31, 2004 to $9.35 per MMBtu as of February 28, 2006. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by o