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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.
(Exact name of registrant as specified in its charter)

(Registrant's telephone number, including area code)
(214) 953-9500

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None.

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

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

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

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Securities Exchange Act. (Check one):

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

         The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $253,615,778 on June 30, 2010, based on $10.54 per unit, the closing price of the Common Units as reported on The NASDAQ Global Select Market on such date.

         At February 11, 2011, there were 50,452,761 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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TABLE OF CONTENTS

DESCRIPTION

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CROSSTEX ENERGY, L.P.

PART I

Item 1.    Business

General

        Crosstex Energy, L.P. is a publicly traded Delaware limited partnership formed in 2002. Our Common Units are listed on The NASDAQ Global Select Market under the symbol "XTEX". Our business activities are conducted through our subsidiary, Crosstex Energy Services, L.P., a Delaware limited partnership (the "Operating Partnership") and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.crosstexenergy.com. In the "Investors" section of our web site, we post the following filings as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual report on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our web site are available free of charge. In this report, the terms "Partnership" and "Registrant," as well as the terms "our," "we," "us" and "its," are sometimes used as abbreviated references to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. together with its consolidated subsidiaries, including the Operating Partnership.

        We are an independent midstream energy company engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs. We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee.

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        Crosstex Energy GP, LLC, a Delaware limited liability company, is our general partner. Crosstex Energy GP, LLC manages our operations and activities. Crosstex Energy GP, LLC is a wholly owned subsidiary of Crosstex Energy, Inc., or CEI. Crosstex Energy, Inc.'s shares are listed on The NASDAQ Global Select Market under the symbol "XTXI." The following diagram depicts the organization and ownership of the Partnership as of January 1, 2011.

        As generally used in the energy industry and in this document, the following terms have the following meanings:

/d = per day
Bbls = barrels
Bcf = billion cubic feet
Btu = British thermal units
Gal = gallon
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid

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        Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (Bcf, Mcf or MMcf). Throughput volumes are measured based on energy content and stated in British thermal units (Btu or MMBtu). A volume capacity of 100 MMcf generally correlates to volume throughput of 100,000 MMBtu. Fractioned volumes are measured based on physical volumes and stated in gallons (Gal).

Our Operations

        We focus on the gathering, processing, transmission and marketing of natural gas and NGLs, which we manage as regional reporting segments. Our geographic focus is in the North Texas Barnett Shale (NTX) and in Louisiana which has two reportable business segments (the Crosstex LIG and the south Louisiana processing and NGL assets, or PNGL). Our combined midstream assets consist of over 3,300 miles of natural gas gathering and transmission and NGL pipelines, nine natural gas processing plants and three fractionators. Our gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plants remove NGLs from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso- and normal butanes and natural gasoline. See Note 15 to the consolidated financial statements for financial information about these operating segments.

        Our assets include the following:

•

North Texas Assets.  Our North Texas Assets are comprised of gathering, processing and transmission assets serving producers active in the Barnett Shale. Our gathering systems in north Texas, or NTG, consist of approximately 670 miles of gathering lines with total capacity of approximately 1,200 MMcf/d and total throughput was approximately 730,000 MMBtu/d for the year ended December 31, 2010. Our processing facilities in north Texas include three gas processing plants with a total processing capacity of 280 MMcf/d. Total processing throughput averaged 209,000 MMBtu/d for the year ended December 31, 2010. Our transmission asset consists of a 140-mile pipeline from an area near Fort Worth, Texas to a point near Paris, Texas and related facilities. The capacity on the North Texas Pipeline, or NTP, is approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos, Gulf Crossing and other markets. For the year ended December 31, 2010, the total throughput on the NTP was approximately 339,000 MMBtu/d.



•

Crosstex LIG System.  The Crosstex LIG system is one of the largest intrastate pipeline systems in Louisiana, consisting of approximately 2,000 miles of gathering and transmission pipeline, with an average total throughput of approximately 902,000 MMBtu/d for the year ended December 31, 2010. The system also includes two operating, on-system processing plants, our Plaquemine and Gibson plants, with an average throughput of approximately 283,000 MMBtu/d for the year ended December 31, 2010. Total volume of fractionated liquids at Plaquemine averaged 2,600 Bbls/d for the year ended December 31, 2010. The system has access to both rich and lean gas supplies. These supplies reach from the Haynesville Shale in north Louisiana to onshore production in south central and southeast Louisiana. Crosstex LIG has a variety of transportation and industrial sales customers, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.



•

South Louisiana Processing and NGL Assets.  Our south Louisiana natural gas processing and liquids assets include approximately 2.0 Bcf/d of processing capacity, 64,000 Bbls/d of fractionation capacity, 2.4 million barrels of underground storage and approximately 440 miles of

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liquids transport lines. The assets include the Eunice processing plant and fractionation facility; the Pelican, Sabine and Blue Water processing plants; the Riverside fractionation plant; the Napoleonville storage facility; the Cajun Sibon pipeline system and the Intracoastal Pipeline. Total processing throughput averaged 874,000 MMBtu/d for the year ended December 31, 2010. Total volume of fractionated liquids averaged 19,000 Bbls/d for the year ended December 31, 2010. The Eunice plant is connected to onshore gas supply, as well as continental shelf and deepwater gas production. The Pelican and Sabine plants are connected with continental shelf and deepwater gas. The various plants have downstream connections to the ANR Pipeline, Florida Gas Transmission, Texas Gas Transmission, Tennessee Gas Pipeline and Transco.

Our Business Strategy

        During 2010, we successfully executed our business plan by improving existing system profitability, improving our financial flexibility and resuming our distributions to partners. We are now well positioned to focus on increasing our distributable cash flow by (i) expanding our existing assets, (ii) capitalizing on our NGL capabilities, (iii) pursuing accretive acquisitions or construction of facilities in new areas and (iv) focusing on operational excellence. Key elements of our strategy will include the following:

•

Undertake selective construction and expansion opportunities on our existing systems. We intend to leverage our existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for our gathering, transmission, processing and marketing services. We have two expansion projects that are underway in north Texas and scheduled for completion near the end of the first quarter of 2011. We are constructing a compressor station on an existing gathering line in north Texas at an estimated cost of less than $10.0 million to accommodate 50 MMcf/d of natural gas. This project will provide the capacity to meet the transportation requirements under a 10 year firm transportation agreement with a major Barnett Shale producer. The annual cash flow from the agreement is expected to be approximately $8.0 million. Our second project involves a 15 mile expansion of our natural gas gathering system in the Barnett Shale with an estimated cost of $25.0 million. The project is supported by volumetric commitments from a major gas producer. Cash flow from this project is expected to average approximately $10.0 million per year for the first four years.



•

Capitalizing on our NGL capabilities.  We believe there are near-term growth opportunities for our NGL business based on our ability to increase the utilization of our asset infrastructure which has excess capacity. We are targeting projects that create incremental stable fee-based income from our NGL fractionation business. We see a growing need for fractionation and NGL handling from liquids-rich gas production from the developing shale plays, including the Eagle Ford shale play in south Texas, the Granite Wash in the Texas Panhandle and Oklahoma, the Marcellus shale play in West Virginia and Pennsylvania and the Bakken shale play in North Dakota. These areas have limited NGL markets and/or inadequate NGL infrastructure. We are currently offering producers in these regions an interim solution by transporting NGLs via rail or truck to our fractionators in Louisiana. During 2010, we were handling approximately 7,300 Bbls/d under these type of arrangements. We have initiated construction on a project to bring 15,000 Bbls/d of idle fractionation capacity at our Eunice plant back into service which is expected to be completed during the first quarter of 2011 with an estimated cost of $9.0 million. The project is supported with existing system volumes and is expected to generate annual cash flow of approximately $3.0 million and will provide capacity for continued growth from our NGL rail aggregation business.



•

Pursue accretive acquisitions or construction of facilities in new areas.  We will also consider the acquisition and construction of facilities and systems in new areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas

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that lack midstream infrastructure to process and/or transport the natural gas. We believe our existing infrastructure, personnel, producer and consumer relationships, and construction experience, including experience in large shale developments, provide us with a competitive advantage for such expansion opportunities. We believe our spare NGL fractionation capacity in south Louisiana will provide a strategic advantage in competing to provide midstream services in many of the newly developing liquids-rich, unconventional gas resources. We intend to use our acquisition and integration experience to make strategic acquisitions of assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset.

•

Focus on operational excellence.  We continue to operate our existing asset base to maximize cost efficiencies, provide flexibility for our customers and provide reliable capacity for our customers. We will continue to focus on safety, environmental integrity, innovation and customer service.

Recent Developments

        We resumed making quarterly distributions to our common unitholders during the third quarter of 2010. In November 2010, we paid a quarterly distribution of $0.25 per unit related to the three months ended September 30, 2010. We declared a quarterly distribution of $0.26 per unit in January 2011 that was paid in February 2011 related to the three months ended December 31, 2010. We believe the resumption of our distributions is an important milestone in accessing the capital markets to support our future growth strategies.

        Prior to December 31, 2010, our general partner was Crosstex GP, L.P., and Crosstex Energy GP, LLC, as the general partner of Crosstex Energy GP, L.P., managed our operations and activities on behalf of Crosstex Energy GP, L.P. On December 31, 2010, Crosstex Energy GP, L.P. merged with and into Crosstex Energy GP, LLC, thereby eliminating the separate existence of Crosstex Energy GP, L.P. In connection with such merger, Crosstex Energy GP, LLC became the general partner of the Partnership and is responsible for managing the operations and activities of the Partnership and for employing the Partnership's officers.

Our Assets

        North Texas Assets.    Our NTP which commenced service in April 2006, consists of a 140-mile pipeline and associated gathering lines from an area near Fort Worth, Texas to a point near Paris, Texas. The capacity of the NTP is approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos, Gulf Crossing and other markets. NTP's interconnect with Gulf Crossing Pipeline provides our customers access to mid-west and east coast markets. For the year ended December 31, 2010, the total throughput on the NTP was approximately 339,000 MMBtu/d.

        On June 29, 2006, we acquired the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.3 million. The acquired systems included gathering pipelines, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that transaction, approximately 160,000 net acres previously owned by Chief and acquired by Devon simultaneously with our acquisition, as well as 60,000 net acres owned by other producers, were dedicated to the systems. Immediately following the closing of the Chief acquisition, we began expanding our north Texas gathering system.

•

Gathering System.  Since the date of the acquisition through December 31, 2010, we have expanded our gathering system and connected in excess of 600 new wells to our north Texas gathering system, including approximately 100 wells connected in 2010, and significantly increased the productive acreage dedicated to the system. As of December 31, 2010, total

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capacity on our north Texas gathering system was approximately 1,200 MMcf/d and total throughput averaged approximately 730,000 MMBtu/d for the year ended December 31, 2010. We have two expansion projects that are underway on our north Texas gathering system and scheduled for completion by the end of the first quarter of 2011. These two expansion projects are supported by volumetric commitments from two separate producers on our north Texas gathering system. We are constructing a compressor station on an existing gathering line to accommodate 50 MMcf/d of natural gas to meet transportation requirements under a 10-year firm transportation agreement with one major producer and adding 15 miles of gathering pipeline in the Barnett Shale for another major producer. The total cost of these two projects is estimated to be approximately $35.0 million.

•

Processing Facilities.  Since 2006, we have constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including our Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, our Azle plant, which is a 50 MMcf/d cryogenic processing plant and our Goforth plant, which is a 30 MMcf/d processing plant. Total processing throughput averaged 209,000 MMBtu/d for the year ended December 31, 2010.

        We have budgeted approximately $30.0 million for continued development of our north Texas assets during 2011, primarily related to our two north Texas gathering system projects discussed above.

        Crosstex LIG Assets.    The Crosstex LIG system is one of the largest intrastate pipeline systems in Louisiana, consisting of approximately 2,000 miles of gathering and transmission pipeline, with an average throughput of approximately 902,000 MMBtu/d for the year ended December 31, 2010. The system also includes two operating, on-system processing plants, our Plaquemine and Gibson plants, with an average throughput of 283,000 MMBtu/d for the year ended December 31, 2010 and total capacity of 335 MMcf/d. The Plaquemine plant also has a fractionation capacity of 10,800 Bbls/d of liquid products which we are connecting to our south Louisiana NGL system in conjunction with the restart of our Eunice fractionator as discussed below. The system has access to both rich and lean gas supplies. These supplies reach from north Louisiana to onshore production in south central and southeast Louisiana. Crosstex LIG has a variety of transportation and industrial sales customers, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.

        In 2007, we expanded our Crosstex LIG system in the north to reach additional productive areas in the developing natural gas fields south of Shreveport, Louisiana, primarily in the Cotton Valley formation. This north Louisiana expansion consists of 63 miles of 24" mainline with 9 miles of gathering lateral pipeline. Our north Louisiana expansion bisects the developing Haynesville Shale gas play in north Louisiana. The north Louisiana expansion was operating at near capacity during 2008 as the Haynesville gas was beginning to develop so we added 35 MMcf/d of capacity by adding compression during the third quarter of 2008 bringing the total capacity of the north Louisiana expansion to approximately 275 MMcf/d. We continued the expansion of our north Louisiana system and increased capacity by 135 MMcf/d during 2009 and 55 MMcf/d in 2010 by adding compression and by building new interconnects to nearby pipelines bringing capacity to 465 MMcf/d by the end of 2010. We have long-term firm transportation agreements subscribing to all of the incremental capacity added during 2009 and 2010. In addition, we added compression during 2009 between the southern portion of our Crosstex LIG system and the northern expansion of our Crosstex LIG system, which increased the capacity to move gas from the north LIG system to our markets in the south to 145 MMcf/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission, Trunkline Gas and Tennessee Gas Pipeline.

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        South Louisiana Processing and NGL Assets.    Our south Louisiana assets are NGL fractionation, storage and pipeline assets and natural gas processing plants generally located near the Louisiana Gulf Coast and include the following:

•

NGL Assets.  Our NGL assets include our Eunice processing plant and fractionation facility, our Riverside fractionation plant, our Cajun Sibon pipeline system and our Napoleonville storage facility. We had excess capacity on our NGL assets during 2008 and 2009 and have made numerous operational changes and reconfigured operations to manage the lower utilization and reduce operating costs. During 2010, we have increased our focus on our NGL business in response to growing NGL supplies from new shale development by seeking additional volumes for fractionation through increased rail and truck deliveries and increased third-party pipeline rich gas supplies. Looking into 2011, we believe NGL supplies will continue to grow so we expect to see continued growth in our NGL business which will increase utilization of our facilities.



•

Eunice Processing Plant and Fractionation Facility.    The Eunice processing plant is located in south central Louisiana, has a capacity of 750 MMcf/d and processed approximately 412,000 MMBtu/d for the year ended December 31, 2010. The plant is connected to onshore gas supply, as well as continental shelf and deepwater gas production and has downstream connections to the ANR Pipeline, Florida Gas Transmission and Texas Gas Transmission, or TGT. The Eunice fractionation facility has a capacity of 36,000 Bbls/d of liquid products, including ethane, propane, iso-butane, normal butane and natural gasoline, and is directly connected to the southeast propane market and pipelines to the Anse La Butte storage facility. The plant was idled in August 2007, and the liquids from the Eunice processing plant were transported through our Cajun Sibon pipeline system to our Riverside plant for fractionation. We plan to restart our Eunice fractionator by the end of the first quarter of 2011 to take advantage of the activity around the liquid rich shale-plays, including the Eagle Ford, Permian, Granite Wash, Marcellus and Bakken plays. As part of this project, we will connect the Plaquemine fractionator into our NGL system for increased operational flexibility. This expansion will give us operational flexibility, increased fractionation capacity, and the ability to capture new NGL-related business. We expect to resume operations with an initial capacity to accommodate 15,000 Bbls/d of NGLs at Eunice and 10,800 Bbls/d at Plaquemine with the additional 21,000 Bbls/d of capacity at Eunice available for restart at a later date, as needed. The estimated cost to restart the fractionator and associated pipelines and facilities will be approximately $9.0 million. The project is supported by existing system volumes and is expected to generate annual cash flow of approximately $3.0 million and will provide capacity for continued growth from our NGL rail aggregation business.



•

Riverside Fractionation Plant.    The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of approximately 28,000 Bbls/d of liquids products and fractionates liquids delivered by the Cajun Sibon pipeline system from the Eunice, Pelican and Blue Water plants or by truck. The Riverside facility has above-ground storage capacity of approximately 102,000 barrels. We have recently completed a project to reduce the fuel requirements at this facility by 15.0%.



•

Cajun Sibon Pipeline System.    The Cajun Sibon pipeline system consists of approximately 440 miles of 6" and 8" pipelines with a system capacity of approximately 28,000 Bbls/d and includes the 62 mile Intracoastal Pipeline acquired in December 2009. The pipeline transports unfractionated NGLs, referred to as raw make, from the Eunice, Pelican and Blue Water plants to either the Riverside or Eunice fractionators or to third party fractionators when necessary, and will be connected to the Plaquemine fractionator in 2011.

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•

Napoleonville Storage Facility.    The Napoleonville NGL storage facility, located outside of Belle Rose, Louisiana, is connected to the Riverside facility and has a total capacity of approximately 2.4 million barrels of underground storage from two existing caverns. The caverns are currently operated in propane and butane service and space is leased to customers for a fee.



•

Pelican Processing Plant.  The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. For the year ended December 31, 2010, the plant processed approximately 278,000 MMBtu/d. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. We have recently established an interconnection with the LIG pipeline for optimization of processing opportunities.



•

Sabine Pass Processing Plant.  The Sabine Pass processing plant is located east of the Sabine River at Johnson's Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. The Sabine Pass plant is connected to continental shelf and deepwater gas production with downstream connections to Florida Gas Transmission, Tennessee Gas Pipeline (TGP) and Transco. The plant processed approximately 107,000 MMBtu/d for the year ended December 31, 2010.



•

Blue Water Gas Processing Plant.  We own a 59.27% interest in the Blue Water gas processing plant and operate the plant. The Blue Water plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. The plant has a net capacity to our interest of 300 MMcf/d. In January 2009, the flow of the gas on the pipeline was reversed by the TGP, the owner of the pipeline, thereby removing access to all the gas processed at our Blue Water plant from the Blue Water offshore system. The gas composition of the reverse TGP stream is leaner in NGL content, but is profitable to process during periods of high fractionation spreads. The plant has operated periodically during 2010 and is expected to continue to operate periodically in the future as fractionation spreads and volumes dictate.

        We have budgeted approximately $9.5 million of capital expenditures for our south Louisiana processing and NGL assets during 2011, primarily comprised of the costs associated with the Eunice restart project and the Plaquemine interconnection.

Industry Overview

        The following diagram illustrates the gathering, processing, fractionation and transmission process.

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        The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-user markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

        Natural gas gathering.    The natural gas gathering process follows the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

        Compression.    Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Because wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is 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 allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it will be unable to overcome the higher gathering system pressure. In contrast, if field compression is installed, a declining well can continue delivering natural gas.

        Natural gas processing.    The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Natural gas produced by a well may not be suitable for long-haul pipeline transportation or commercial use and may need to be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream, as well as the removal of contaminants.

        NGL fractionation.    Fractionation is the process by which NGLs are further separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. 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 ethylene and propylene and as a heating fuel, an engine fuel and industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutene through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.

        Natural gas transmission.    Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, processing plants, and gathering systems and deliver it to industrial end-users, utilities and to other pipelines.

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Balancing of Supply and Demand

        As we purchase natural gas, we establish a margin normally by selling natural gas for physical delivery to third-party users. We can also use over-the-counter derivative instruments or enter into a future delivery obligation under futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is not to acquire and hold natural gas futures contracts or derivative products for the purpose of speculating on price changes.

Competition

        The business of providing gathering, transmission, processing and marketing services for natural gas and NGLs is highly competitive. We face strong competition in obtaining natural gas supplies and in the marketing and transportation of natural gas and NGLs. Our competitors include major integrated oil companies, natural gas producers, interstate and intrastate pipelines and other natural gas gatherers and processors. Competition for natural gas supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. Many of our competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do. Our competition differs in different geographic areas.

        In marketing natural gas and NGLs, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas producers, gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

        We face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses, and results in fewer commitments and lower returns for new pipelines or other development projects. Many of our competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. Our competition differs by region and by the nature of the business or the project involved.

Natural Gas Supply

        Our transmission pipelines have connections with major interstate and intrastate pipelines, which we believe have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of our gathering systems, we evaluate well and reservoir data publicly available or furnished by producers or other service providers to determine the availability of natural gas supply for the systems and/or obtain a minimum volume commitment from the producer that results in a rate of return on investment. Based on these facts, we believe that there should be adequate natural gas supply to recoup our investment with an adequate rate of return. We do not routinely obtain independent evaluations of reserves dedicated to our systems due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

        We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability.

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        During the year ended December 31, 2010, we had three customers that represented greater than 10.0% individually of our revenue. Two customers in our LIG segment represented 14.5% and 10.6% of our consolidated revenue. One customer in our NTX segment represented 10.2% of our consolidated revenue. While these customers represents a significant percentage of consolidated revenues, the loss of these customers would not have a material impact on our results of operations because the gross operating margins received from transactions with these customers are not material to our total gross operating margin and we believe the sales to these customers could be easily replaced with other buyers at comparable sales prices.

Regulation

        Regulation by FERC of Interstate Natural Gas Pipelines.    We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or FERC, does not directly regulate our operations under the National Gas Act, or NGA. However, FERC's regulation of interstate natural gas pipelines influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

•

the certification and construction of new facilities;



•

the extension or abandonment of services and facilities;



•

the maintenance of accounts and records;



•

the acquisition and disposition of facilities;



•

maximum rates payable for certain services; and



•

the initiation and discontinuation of services.

        While we do not own any interstate pipelines, we do transport gas in interstate commerce. The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. In addition, FERC has adopted, or is in the process of adopting, various regulations concerning natural gas market transparency that will apply to some of our pipeline operations. The maximum rates for services provided under Section 311 of the NGPA may not exceed a "fair and equitable rate," as defined in the NGPA. The rates are generally subject to review every three years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations, the inability to achieve adequate returns on investments in new facilities and the deterrence of future investment or growth of the regulated facilities.

        Intrastate Pipeline Regulation.    Our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state 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.

        Gathering Pipeline Regulation.    Section 1(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. 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.

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        We are subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.

        Sales of Natural Gas.    The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by 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 those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations but we do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Environmental Matters

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

        Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures and obtaining required governmental approvals, may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays. We believe that we currently hold all material governmental approvals required to operate our major facilities. As part of the regular overall evaluation of our operations, we have implemented procedures to review and update governmental approvals as necessary. 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 currently in effect will not have a material adverse effect on our operating results or financial condition.

        The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our possible future operations, and we cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to property and persons as a result of any such upsets, releases, or spills. In the event of future increases in environmental costs, we may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent losses related to the event are not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related

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to claims made by neighboring landowners and other third parties for personal injury or damage to natural resources or property. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to more stringent future laws and regulations of more rigorous enforcement of existing laws and regulations.

        Hazardous Substance and Waste.    To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to prevent and control pollution. 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 at facilities where such waste may have been released or disposed. For instance, 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. Potentially liable 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 found at the site. Under CERCLA, these persons may be subject to joint and several 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 EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially 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 wastes 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 ordinary operations, we may generate wastes that may fall within the definition of a "hazardous substance." In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, we may be responsible under CERCLA or other laws 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 any analogous federal or state laws.

        We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and/or comparable state statutes. From time to time, the Environmental Protection Agency, or EPA, and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Changes in applicable laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.

        We currently own or lease, and have in the past owned or leased, and in the future we may own or lease, properties that have been used over the years for natural gas gathering, treating or processing and for NGL fractionation, transportation or storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries 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 on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These

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properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, or to take action to prevent future contamination.

        Air Emissions.    Our current and future 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 facilities, and impose various controls together with monitoring and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air-emission related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition or operating results, and the requirements are not expected to be more burdensome to us than any similarly situated company.

        Air emissions associated with operations in the Barnett Shale area have come under recent scrutiny. In 2009 and 2010, the Texas Commission on Environmental Quality (TCEQ) conducted comprehensive monitoring of air emissions in the Barnett Shale area, in response to public concerns about high concentrations of benzene and other potential emissions in the air near drilling sites and natural gas processing facilities. In addition, environmental groups have advocated increased regulation in the Barnett Shale area and these groups as well as at least one state representative have further advocated a moratorium on permits for new gas wells until TCEQ completes its analysis. Also, the EPA recently entered into a settlement that requires it to reevaluate regulations for the control of air emissions from natural gas production facilities. Changes in laws or regulations imposing emission limitations, pollution control technology requirements or other regulatory requirements or any restriction on permitting of natural gas production facilities in the Barnett Shale area could have an adverse effect on our business.

        Climate Change.    In response to concerns suggesting that emissions of certain gases, commonly referred to as "greenhouse gases" (including carbon dioxide and methane), may be contributing to warming of the earth's atmosphere, EPA is taking steps that would result in the regulation of greenhouse gases as pollutants under the federal Clean Air Act.

        In September 2009, EPA finalized its Mandatory Reporting Rule for greenhouse gases, which requires the monitoring and reporting of greenhouse gas emissions on an annual basis. Some of our facilities include source categories that are subject to the greenhouse gas reporting requirements included in the final rule as promulgated in September 2009. In November 2010, EPA expanded the scope of the Mandatory Reporting Rule to include petroleum and natural gas systems, which applies the Mandatory Reporting Rule's requirements to, among other sources, fugitive and vented methane emissions from the oil and gas sector, including natural gas transmission compression. Although the Mandatory Reporting Rule does not control greenhouse gas emission levels from any facilities, it has still caused us to incur monitoring and reporting costs for emissions that are subject to the rule. Further, the rule's new requirements for reporting of fugitive and vented methane emissions from the oil and gas industry can be expected to increase our monitoring and reporting costs during 2011.

        After a series of regulatory actions finalized by EPA between December 2009 and May 2010, greenhouse gases became pollutants "subject to regulation" under the Clean Air Act's Prevention of Significant Deterioration (PSD) air quality permit program for stationary sources, and the largest of

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these sources have also become subject to permitting requirements under the Clean Air Act's Title V permitting program. As a result, new major stationary sources of greenhouse gas emissions, and modifications of existing major stationary sources that significantly increase their greenhouse gas emissions will require a permit setting forth Best Available Control Technology (BACT) for those emissions. EPA has, through its "Tailoring Rule," acted to limit these permitting requirements to only the largest sources of greenhouse gas emissions initially, but these new requirements could in the future affect our operations and our ability to obtain air permits for new or modified facilities.

        The U.S. Congress has also considered legislation to mandate reductions of greenhouse gas emissions, and at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs.

        Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect the demand for the products we store, transport, and process, and depending on the particular program adopted could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

        Clean Water Act.    The Federal Water Pollution Control Act, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. 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 continued compliance with such existing permit conditions will not have a material effect on our results of operations.

        It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by our customers, particularly in Barnett Shale and Haynesville Shale regions of our operations. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. At the federal level, the last U.S. Congress introduced legislation that would have amended the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. As support for the chemical disclosure requirements included in the legislation, sponsors of the

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legislation asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. This legislation could be reintroduced to the current Congress. If adopted, this or other similar legislation could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for our customers to perform hydraulic fracturing. In addition, during the first quarter of 2010, the EPA initiated a detailed scientific study of hydraulic fracturing and its potential impacts on surface and ground waters. The initial study results are expected to be available in late 2012. In early 2010, EPA also indicated in a website posting that it intended to regulate hydraulic fracturing under the Safe Drinking Water Act and require permitting for any well where hydraulic fracturing was conducted with the use of diesel as an additive. While industry groups have challenged EPA's website posting as improper rulemaking, the Agency's position, if upheld could require additional permitting and could lead to operations delays, increased costs and regulatory burdens that could make it more difficult for our customers to perform hydraulic fracturing. State and local governments have also considered proposed regulations addressing public concerns related to hydraulic fracturing operations. Some state and local governments in the Marcellus Shale region, have considered or imposed moratoriums on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by EPA or the relative state agencies are completed. Any increased federal, state or local regulation could reduce the volumes of natural gas that our customers move through our gathering systems which would materially adversely affect our revenues and results of operations.

        Employee 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.

        DOT Safety Regulations.    Our pipelines are subject to regulation by the U.S. Department of Transportation. The Department of Transportation's (DOT) and the Pipeline Hazardous Material Safety Administration (PHMSA), acting through the Office of Pipeline Safety (OPS), administers the national regulatory program to assure the safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. OPS develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities. These safety regulations are listed under 49 CFR, Parts 192 and 195 and those referenced therein. Pipelines that transport natural gas are governed under DOT 49 CFR 192. Pipelines that transport crude oil, carbon dioxide, NGL and petroleum products are governed under DOT 49 CFR 195. PHMSA requires any entity which owns or operates pipeline facilities to comply with the regulations under these and referenced regulations, regarding access to and allow copying of records, and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas, amendments to 49 CFR Part 192 and 195 (PIM) requires operators of transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. In addition, the Railroad Commission of Texas, or TRRC, regulates our pipelines in Texas under its own pipeline integrity management rules. The Texas rule includes certain transmission based upon pipeline diameter and operating pressures. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and PIM requirements; however, due to the possibility

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of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the PHMSA or PIM requirements will not have a material adverse effect on our results of operations or financial positions.

Office Facilities

        We occupy approximately 95,400 square feet of space at our executive offices in Dallas, Texas under a lease expiring in June 2014, approximately 25,100 square feet of office space for our Louisiana operations in Houston, Texas with lease terms expiring in January 2013. We have approximately 17,000 square feet of office space in Fort Worth, Texas with lease terms expiring in April 2013 and currently have this space sub-leased to other tenants.

Employees

        As of December 31, 2010, we (through our subsidiaries) employed approximately 469 full-time employees. Approximately 173 of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.

Item 1A.    Risk Factors

        The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are described below, may also impair our business operations. If any of the following risks occur, our business, financial condition or results of operations could be affected materially and adversely. In that case, we may be unable to make distributions to our unitholder and the trading price of our common unit could decline. These risk factors should be read in conjunction with the other detailed information concerning us set forth in our accompanying financial statements and notes and contained in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included herein.

Risks Inherent In Our Business

Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.

        We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing component of our business. For the year ended December 31, 2010 approximately 10.6% of our processed gas arrangements, based on volume, was processed under percent of liquids (POL) contracts. Under these contracts we receive a fee in the form of a percentage of the liquids recovered and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under these contracts are directly impacted by the market price of NGLs.

        We also realize processing gross margins under processing margin (margin) contracts. For the year ended December 31, 2010 approximately 12.9% of our processed gas arrangements, based on volume, was processed under margin contracts. We have a number of margin contracts on our Plaquemine and Gibson processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost ("shrink") and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. Our margins from these contracts can be negative during periods of high natural gas prices relative to liquids prices.

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        We are also indirectly exposed to commodity prices due to the negative impacts on production and the development of production of natural gas and NGLs connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products will reduce the demand for our services and volumes on our systems.

        In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, prices of natural gas in 2010 were below the market price realized throughout most of 2009 while prices for oil and NGLs were higher than 2009 market prices. Crude oil prices (based on the New York Mercantile Exchange (the "NYMEX") futures daily close prices for the prompt month) in 2010 ranged from a low of $68.01 per Bbl in May 2010 to a high of $91.51 per Bbl in December 2010. Weighted average NGL prices in 2010 (based on the Oil Price Information Service (OPIS) Napoleonville daily average spot liquids prices) ranged from a low of $0.84 per gallon in July 2010 to a high of $1.23 per gallon in January 2010. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2010 ranged from a high of $7.51 per MMBtu in January 2010 to a low of $3.18 per MMBtu in October 2010.

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

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



•

the level of domestic oil and natural gas production;



•

technology, including improved production techniques (particularly with respect to shale development);



•

the level of domestic industrial and manufacturing activity;



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the availability of imported oil, natural gas and NGLs;



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international demand for oil and NGLs;



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actions taken by foreign oil and gas producing nations;



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the availability of local, intrastate and interstate transportation systems;



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the availability of downstream NGL fractionation facilities;



•

the availability and marketing of competitive fuels;



•

the impact of energy conservation efforts; and



•

the extent of governmental regulation and taxation, including the regulation of "greenhouse gases."

        Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas we gather and process. The volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in "—Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income." For a discussion of our risk management activities, please read "Item 7A. Quantitative and Qualitative Disclosure about Market Risk."

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Our substantial indebtedness could limit our flexibility and adversely affect our financial health.

        We have a substantial amount of indebtedness. As of December 31, 2010, we had approximately $732.1 million of indebtedness outstanding primarily comprised of $725.0 million (including $13.5 million of original issue discount) of senior unsecured notes. We also have a bank credit facility with a borrowing capacity of $420.0 million that had approximately $86.6 million of letters of credit outstanding, leaving available capacity of $333.4 million as of December 31, 2010.

        Our substantial indebtedness could limit our flexibility and adversely affect our financial health. For example, it could:

•

make us more vulnerable to general adverse economic and industry conditions;



•

require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow for operations and other purposes;



•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and



•

place us at a competitive disadvantage compared to competitors that may have proportionately less indebtedness.

        In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance. We cannot assure you that our operating performance will generate sufficient cash flow or that our capital resources will be sufficient for payment of our indebtedness obligations in the future. Our financial and operating performance, cash flow and capital resources depend upon prevailing economic conditions and certain financial, business and other factors, many of which are beyond our control.

        If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to sell material assets or operations, obtain additional capital or restructure our debt. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, we cannot assure you as to the terms of any such transaction or how quickly any such transaction could be completed, if at all.

We may not be able to access new capital to fund our acquisition and growth strategies which could impair our ability to fund future capital needs and to grow.

        Global financial markets and economic conditions recently have been disrupted and volatile. These conditions, along with significant write-offs in the financial services sector and current weak economic conditions, have made, and could in the future make, it difficult to obtain funding for our capital needs. As a result, the cost of raising money in the debt and equity capital markets could increase substantially while the availability of funds from those markets could diminish significantly. Due to these factors, we cannot be certain that new debt or equity financing will be available to us on acceptable terms or at all. Without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or future construction projects or other capital expenditures, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations. Further, our customers may increase collateral requirements from us, including letters of credit which reduce available borrowing capacity, or reduce the business they transact with us to reduce their credit exposure to us.

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Due to our lack of asset diversification, adverse developments in our gathering, transmission, processing and NGL services businesses would materially impact our financial condition.

        We rely exclusively on the revenues generated from our gathering, transmission, processing and NGL services businesses and as a result our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

We may not be successful in balancing our purchases and sales.

        We are a party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

        We make certain commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect our margins or even result in losses. For example, we are a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/day of gas. We buy gas for this contract on several different production-area indices on our NTP and sell the gas into a different market area index. For the year ended December 31, 2010 we have recorded a loss of approximately $8.4 million on this contract, and we currently expect that we will record a loss of approximately $10.0 million to $14.0 million on this contract in 2011. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse. For additional information on this contract, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview."

We must continually compete for natural gas supplies, and any decrease in our supplies of natural gas could adversely affect our financial condition and results of operations.

        Our gathering systems are connected to oil and natural gas wells from which production will naturally decline over time, which means that its cash flows associated with these sources of natural gas will likely also decline over time. In order to maintain or increase throughput levels in our natural gas gathering systems and asset utilization rates at our processing plants and to fulfill our current sales commitments, we must continually contract for new natural gas supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near our gathering systems. If we are unable to maintain or increase the throughput on our systems by accessing new natural gas supplies to offset the natural decline in reserves, our business and financial results could be materially, adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

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        Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Natural gas prices were relatively low in 2010 and continue to be depressed. Prolonged periods of low natural gas prices in the future may put downward pressure on drilling activity in the future which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of natural gas available to our systems. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production or in the level of drilling activity in our principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on our results of operations and financial position.

A substantial portion of our assets is connected to natural gas reserves that will decline over time, and the cash flows associated with those assets will decline accordingly.

        A substantial portion of our assets, including our gathering systems, is dedicated to certain natural gas reserves and wells for which the production will naturally decline over time. Accordingly, our cash flows associated with these assets will also decline. If we are unable to access new supplies of natural gas either by connecting additional reserves to our existing assets or by constructing or acquiring new assets that have access to additional natural gas reserves, our cash flows may decline.

We are vulnerable to operational, regulatory and other risks due to our concentration of assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.

        Our operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because we have a significant portion of our assets located in these two areas. Our concentration of activity in Louisiana and the Gulf of Mexico makes us more vulnerable than many of our competitors to the risks associated with these areas, including:

•

adverse weather conditions, including hurricanes and tropical storms;



•

delays or decreases in production, the availability of equipment, facilities or services; and



•

changes in the regulatory environment.

        Because a significant portion of our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other midstream companies who have operations in more diversified geographic areas.

Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

        Our operations expose us to fluctuations in commodity prices, and our credit facility exposes us to fluctuations in interest rates. We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. As of December 31, 2010, we have hedged only portions of our expected exposures to commodity price risk. In addition, to the extent we hedge our commodity price risk using swap instruments, we will forego the benefits of favorable changes in commodity prices. Although we do not currently have any financial instruments to eliminate our exposure to interest rate fluctuations, we may use financial instruments in the future to offset our exposure to interest rate fluctuations.

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        Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:

•

hedging can be expensive, particularly during periods of volatile prices;



•

our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and



•

available hedges may not correspond directly with the risks against which we seek protection. For example:



•

the duration of a hedge may not match the duration of the risk against which we seek protection;



•

variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and



•

we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity, which could adversely affect our liquidity.

        Our financial statements may reflect gains or losses arising from exposure to commodity prices for which we are unable to enter into fully effective hedges. In addition, the standards for cash flow hedge accounting are rigorous. Even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective cash flow hedges for accounting purposes. Our earnings could be subject to increased volatility to the extent our derivatives do not continue to qualify as cash flow hedges, and, if we assume derivatives as part of an acquisition, to the extent we cannot obtain or choose not to seek cash flow hedge accounting for the derivatives we assume. Please read "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" for a summary of our hedging activities.

A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could materially adversely affect our results of operations and financial condition.

        The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and the demand for these products are affected as follows:

•

Ethane.  Ethane is typically supplied as purity ethane or as part of ethane-propane mix. 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. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.

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•

Propane.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.



•

Normal Butane.  Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.



•

Isobutane.  Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.



•

Natural Gasoline.  Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

        NGLs and products produced from NGLs also compete with global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.

Growing our business by constructing new pipelines and processing facilities subjects us to construction risks, risks that natural gas or NGL supplies will not be available upon completion of the facilities and risks of construction delay and additional costs due to obtaining rights-of-way and complying with federal, state and local laws.

        One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new pipelines and gathering and processing facilities. The construction of pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our expectations. Generally, we may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, we face the risks of construction delay and additional costs due to obtaining rights-of-way and local permits and complying with federal or state laws and city ordinances, particularly as we expand our operations into more urban, populated areas such as the Barnett Shale.

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

        Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable

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purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and our ability to increase distributions will be limited.

        From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owner's use. Any acquisition involves potential risks, including:

•

the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;



•

the diversion of management's attention from other business concerns;



•

the failure to realize expected volumes, revenues, profitability or growth;



•

the failure to realize any expected synergies and cost savings;



•

the coordination of geographically disparate organizations, systems and facilities;



•

the assumption of unknown liabilities;



•

the loss of customers or key employees from the acquired businesses;



•

a significant increase in our indebtedness; and



•

potential environmental or regulatory liabilities and title problems.

        Management's assessment of these risks is necessarily inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        Additionally, our ability to grow our asset base in the near future through acquisitions may be limited due to constrained capital markets.

The terms of our credit facility and indenture may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

        Our credit agreement and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. These agreements include covenants that, among other things, restrict our ability to:

•

incur or guarantee additional indebtedness or issue preferred stock;



•

pay dividends on our equity securities or redeem, repurchase or retire our equity securities or subordinated indebtedness;



•

make investments;



•

create restrictions on the payment of dividends or other distributions to its equity holders;



•

engage in transactions with our affiliates;



•

sell assets, including equity securities of our subsidiaries;



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consolidate or merge;

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•

incur liens;



•

prepay, redeem and repurchase certain debt;



•

make certain acquisitions;



•

transfer assets;



•

enter into sale and lease back transactions;



•

make capital expenditures; and



•

change business activities we conduct.

        In addition, our credit facility requires us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

        A breach of any of these covenants could result in an event of default under our credit facility and indenture. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under our senior secured credit facility, the lenders under senior secured credit facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged substantially all of our assets as collateral under our senior secured credit facility. If indebtedness under our senior secured credit facility or indentures is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

We do not own most of the land on which our pipelines and compression facilities are located, which could disrupt our operations.

        We do not own most of the land on which our pipelines and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

We expect to encounter significant competition in any new geographic areas into which we seek to expand and our ability to enter such markets may be limited.

        If we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas supplies and markets. Competitors in these new markets will include companies larger than us, which have both lower capital costs and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, we may not be able to successfully develop acquired assets and markets located in new geographic areas and our results of operations could be adversely affected.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

        The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including

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competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

        In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2010, approximately 49% of our sales of gas that was transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price.

We depend on certain key customers, and the loss of any of our key customers could adversely affect our financial results.

        We derive a significant portion of our revenues from contracts with key customers. To the extent that these and other customers may reduce volumes of natural gas purchased or transported under existing contracts, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers. Certain agreements with key customers provide for minimum volumes of natural gas or natural gas services that require the customer to transport, process or purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Customers may default on their obligations to transport, process or purchase the minimum volumes of natural gas or natural gas services required under the applicable agreements.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse effect on our financial condition and results of operations.

        Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders.

Federal, state or local regulatory measures could adversely affect our business.

        Our natural gas gathering and processing activities generally are exempt from FERC regulation under the Natural Gas Act. However, 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 and the courts. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations also may be or become 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 are 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.

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        The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to FERC regulation under the Section 311 of the Natural Gas Policy Act. Under these regulations, we are required to justify our rates for interstate transportation service on a cost-of-service basis, every three years. Our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Should FERC or any of these state agencies determine that our rates for Section 311 transportation service or intrastate transportation service should be lowered, our business could be adversely affected.

        Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. 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 to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow 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.

        The states in which we conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968. The "rural gathering exemption" under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The "rural gathering exemption," however, may be restricted in the future, and it does not apply to our natural gas transmission pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements.

        Compliance with pipeline integrity regulations issued by the United States Department of Transportation in December 2003 or those issued by the TRRC could result in substantial expenditures for testing, repairs and replacement. TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. Our costs relating to compliance with the required testing under the TRRC regulations, adjusted to exclude costs associated with discontinued operations, were approximately at $1.4 million, $1.1 million, and $1.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. We expect the costs for compliance with TRRC and DOT regulations to be approximately $1.6 million during 2011. If our pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then we may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

        As our operations continue to expand into and around urban, or more populated areas, such as the Barnett Shale, we may incur additional expenses to mitigate noise, odor and light that may be emitted in our operations, and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations, including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.

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Our business involves hazardous substances and may be adversely affected by environmental regulation.

        Many of the operations and activities of our gathering systems, processing plants, fractionators and other facilities are subject to significant federal, state and local environmental laws and regulations. The obligations imposed by these laws and regulations include obligations related to air emissions and discharge of pollutants from our facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for treatment or disposal. Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Strict, joint and several liability may be incurred under these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties near our facilities or upon or through which our gathering systems traverse, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations for releases of contaminants or for personal injury or property damage.

        There is inherent risk of the incurrence of significant environmental costs and liabilities in our business due to our handling of natural gas and other petroleum substances, air emissions related to our operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters containing mercury. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us.

        Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation being considered by the U.S. Congress relating to the control of greenhouse gas emissions or changes in existing environmental laws or regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for natural gas, which could adversely affect our business and our profitability.

Recent events in the Gulf of Mexico may decrease the supplies of natural gas to our south Louisiana assets.

        On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico was declared a Spill of National Significance by the United States Department of Homeland Security. We cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or possible changes in laws or regulations that may be enacted in response to this spill, but this event and its aftermath could adversely affect our operations. Our operations in south Louisiana are dependent upon continued conventional and deep shelf drilling in the Gulf of Mexico. Additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current or future volumes being processed by our facilities, and may potentially reduce volumes in our NGL marketing business.

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Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas that we gather, transport and process.

        Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. Due to concerns that hydraulic fracturing may adversely affect drinking water supplies, in the first quarter of 2010, the EPA initiated a detailed scientific study to investigate the potential adverse impact that hydraulic fracturing may have on water quality and public health. The initial study results are expected to be available in late 2012. Additionally, legislation was introduced in the previous session of the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. This legislation could be reintroduced by the current session of Congress. If enacted, this or similar legislation could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or the implementation of regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas that we gather, transport and process.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.

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

•

damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;



•

inadvertent damage from construction and farm equipment;



•

leaks of natural gas, NGLs and other hydrocarbons; and



•

fires and explosions.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to hedge risks associated with our business.

        The United States Congress has adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on

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July 21, 2010, and requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The CFTC has proposed regulations that may provide to us the certainty that we will not be required to comply with margin requirements, but the timing of the adoption of any such regulations, and their scope, are uncertain. If margin requirements and other trading structures apply to us, the new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on our financial condition and results of operations.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.

        On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allow the EPA to proceed with the adoption and implementation of regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted two sets of regulations under the Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. Moreover, on October 30, 2009, the EPA published a "Mandatory Reporting of Greenhouse Gases" final rule that establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. On April 12, 2010, the EPA proposed to expand its existing GHG reporting rule to include owners and operators of onshore oil and natural gas production, processing, transmission, storage and distribution facilities. If the proposed rule is finalized in its current form, reporting of GHG emissions from such onshore activities would be required on an annual basis beginning in 2012 for emissions occurring in 2011.

        In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of

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operations in the absence of any permits that may be required to regulate emission of greenhouse gases, or could adversely affect demand for the natural gas we gather, process or otherwise handle in connection with our services.

We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

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

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact our results of operations and our ability to raise capital.

        Terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. Our insurance policies generally exclude acts of terrorism. Such insurance is not available at what we believe to be acceptable pricing levels.

Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.

        We depend on the continued employment and performance of the officers of our general partner and key operational personnel. Our general partner has entered into employment agreements with each of its executive officers. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any "key man" life insurance for any officers.

Risk Inherent In An Investment In the Partnership

Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.

        Because distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

        We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon 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;



•

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

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•

the volume of natural gas we gather, treat, compress, process, transport and sell and the volume of NGLs we process or fractionate and sell;



•

the relationship between natural gas and NGL prices;



•

cash settlements of hedging positions;



•

the level of competition from other midstream energy companies;



•

the level of our operating and maintenance and general and administrative costs; 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:

•

the level of capital expenditures we make;



•

our ability to make borrowings under our credit facility to pay distributions;



•

the cost of acquisitions;



•

our debt service requirements and other liabilities;



•

fluctuations in our working capital needs;



•

general and administrative expenses;



•

restrictions on distributions contained in our debt agreements; and



•

the amount of cash reserves established by our general partner for the proper conduct of our business.

Crosstex Energy, Inc., or CEI, controls our general partner and owned a 25.0% fully diluted limited partner interest in us as of December 31, 2010. Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests.

        As of December 31, 2010, CEI indirectly owned an aggregate fully diluted limited partner interest of approximately 25.0% in us. In addition, CEI owns and controls our general partner. Due to its control of our general partner and the size of its limited partner interest in us, CEI effectively controls all limited partnership decisions, including any decisions related to the removal of our general partner. Conflicts of interest may arise in the future between CEI and its affiliates, including our general partner, on the one hand, and our partnership, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over our interests. These conflicts include, among others, the following situations:

Conflicts Relating to Control

•

our partnership agreement limits our general partner's liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner;



•

in resolving conflicts of interest, our general partner is allowed to take into account the interests of parties in addition to unitholders, which has the effect of limiting its fiduciary duties to the unitholders;



•

our general partner's affiliates may engage in limited competition with us;



•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

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•

our general partner decides whether to retain separate counsel, accountants or others to perform services for us;



•

in some instances our general partner may cause us to borrow funds from affiliates of the general partner or from third parties in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions; and



•

our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

Conflicts Relating to Costs

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves;



•

our general partner determines which costs incurred by it and its affiliates are reimbursable by us; and



•

our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our unitholders have no right to elect our general partner or the directors of its general partner and have limited ability to remove our general partner.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of its general partner and have no right to elect our general partner or the board of directors of its general partner on an annual or other continuing basis.

        Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 66²/3% of the outstanding units voting together as a single class. Affiliates of the general partner controlled approximately 27.0% of all the units as December 31, 2010.

        In addition, unitholders' voting rights are further restricted by the partnership agreement. It provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

        As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first negotiating such a purchase with our general partner and, as a result, our unitholders are less likely to receive a takeover premium.

Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to our unitholders.

        Prior to making any distributions on the units, we reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses.

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

        The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.

Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

        Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

Our partnership agreement contains provisions that reduce the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

        Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The partnership agreement also restricts the remedies available to our unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.

We may issue additional units without our unitholders' approval, which would dilute our unitholders' ownership interests.

        We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional limited partner interests will have the following effects:

•

our unitholders' proportionate ownership interest in us will decrease;



•

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



•

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



•

the market price of the common units may decline.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.

Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

        Our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace

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our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business, to the extent that a person who has transacted business with the partnership reasonably believes, based on our unitholders' conduct, that our unitholders are a general partner. Our general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.

Tax Risks to Our Unitholders

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

        The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

        If we were treated as a corporation for federal income tax purposes, we would pay additional tax on our income at corporate rates of up to 35.0% (under the law as of the date of this report) and we would probably pay state income taxes as well. In addition, distributions to unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders and thus would likely result in a material reduction in the value of the common units.

        Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. At the state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 1.0% of our gross income apportioned to Texas in the prior year. If federal income tax or material amounts of additional state tax were to be imposed on us, the cash available for distribution to unitholders could be reduced and/or the value of an investment in our common units would be adversely impacted. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be decreased to reflect the impact of that law on us.

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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any contest could reduce the cash available for distribution to our unitholders.

        We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel's conclusions expressed in this annual report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with all of our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne by us and therefore indirectly by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution by us.

Unitholders may be required to pay taxes on our income even if they do not receive any cash distributions from us.

        Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay federal income taxes and, in some cases, state, local, and foreign income taxes on their share of our taxable income even if they do not receive cash distributions from us. Unitholders may not receive cash distributions equal to their share of our taxable income or even the tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be different than expected.

        Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated for a common unit, which decreased the tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, a unitholder who sells units may incur a tax liability in excess of the amount of cash received from the sale.

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

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

We will determine the tax benefits that are available to an owner of units without regard to the specific units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of

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tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of unitholders.

The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder who has adopted a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination would cause us to be treated as a new partnership for tax purposes, and we could be subject to penalties if we were to fail to recognize and properly report on our tax return that a termination occurred.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

As a result of investing in our common units, you will likely be subject to state and local taxes and return filing or withholding requirements in jurisdictions where you do not live.

        In addition to federal income taxes, you will likely be subject to other taxes such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state and local tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and you may be subject to penalties for failure to comply with those requirements. We own property or conduct business in Texas and Louisiana. Louisiana imposes an income tax, generally. Texas does not impose a state income tax on individuals, but does impose a franchise tax to which we are subject. We may do business or own property in other states or foreign countries in the future. It is our unitholders' responsibility to file all federal, state, local, and foreign tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.

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

        We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

        Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Item 1B.    Unresolved Staff Comments

        We do not have any unresolved staff comments.

Item 2.    Properties

        A description of our properties is contained in "Item 1. Business."

Title to Properties

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

        We believe that we have satisfactory title to all of our rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or

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defects should materially detract from the value of our assets or from our interest in these assets or should materially interfere with their use in the operation of the business.

Item 3.    Legal Proceedings

        Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, property use or damage and personal injury. Additionally, as we continue to expand operations into more urban, populated areas, such as the Barnett Shale, we may see an increase in claims brought by area landowners, such as nuisance claims and other claims based on property rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial results on our operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure 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.

        On June 7, 2010, Formosa Plastics Corporation, Texas, Formosa Plastics Corporation America, Formosa Utility Venture, Ltd., and Nan Ya Plastics Corporation, America filed a lawsuit against Crosstex Energy, Inc., Crosstex Energy, L.P., Crosstex Energy GP, L.P., Crosstex Energy GP, LLC, Crosstex Energy Services, L.P., and Crosstex Gulf Coast Marketing, Ltd. in the 24^th Judicial District Court of Calhoun County, Texas, asserting claims for negligence, res ipsa loquitor, products liability and strict liability relating to the alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership. The lawsuit alleges that the plaintiffs have incurred at least $65.0 million in damages, including damage to equipment and lost profits. The Partnership has submitted the claim to its insurance carriers and intends to vigorously defend the lawsuit. The Partnership believes that any recovery would be within applicable policy limits. Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

        At times, our gas-utility subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain provided under state law. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership's gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

        The Partnership (or its subsidiaries) is defending a number of lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.

Item 4.    Reserved

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PART II

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

        Our common units are listed on The NASDAQ Global Select Market under the symbol "XTEX". On February 11, 2011, the closing market price for the common units was $15.63 per unit and there were approximately 14,151 record holders and beneficial owners (held in street name) of our common units.

        The following table shows the high and low closing sales prices per common unit, as reported by The NASDAQ Global Select Market, for the periods indicated.

        Unless restricted by the terms of our credit facility, within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:

•

provide for the proper conduct of our business;



•

comply with applicable law, any of our debt instruments, or other agreements; or



•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;



•

plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on the date of determination of available cash.

        We do not currently intend to make cash distributions on our outstanding units unless our total debt to adjusted EBITDA is less than 4.5 to 1.0 (pro forma for any distribution). See discussion under "Item 6. Selected Financial Data—Non-GAAP Financial Measures."

        Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98.0% to unitholders and two percent to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 13.0%, 23.0% and 48.0% based on incremental distribution thresholds as set forth in our partnership agreement.

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        We resumed making quarterly distributions to our common unitholders for the third quarter of 2010. In November 2010, we paid a quarterly distribution of $0.25 per unit related to the three months ended September 30, 2010. In February 2011, we paid a quarterly distribution of $0.26 per unit, related to the three months ended December 31, 2010.

        On January 19, 2010, we issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions. The 14,705,882 preferred units are convertible at any time into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. We have the right to force conversion of the preferred units after three years from the issuance date if (i) the daily volume-weighted average trading price of our common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 days ending on two trading days before the date on which we deliver notice of such conversion, and (ii) the average daily trading volume of common units must have exceeded 250,000 common units for 20 out of the trailing 30 trading days ending on two trading days before the date on which we deliver notice of such conversion. The preferred units are not redeemable but will pay a quarterly distribution that is the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if we pay a cash distribution on common units. We paid aggregate cash distributions on the preferred units of $3.1 million, $3.1 million, $3.7 million and $3.8 million related to the first, second, third and fourth quarters of 2010, respectively.

Item 6.    Selected Financial Data

        The following table sets forth selected historical financial and operating data of Crosstex Energy, L.P. as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, L.P. and have been revised to reflect certain immaterial corrections. The corrections did not impact the Partnership's operating income and were not material to the Partnership's revenues and costs for the applicable period. These corrections include reporting, on a gross basis, certain revenues and purchased gas and NGL costs associated with its NGL marketing activities previously reported on a net basis for the years ended December 31, 2009 and 2008. In addition, the revised financials also reflect a reclassification of certain intercompany revenues and purchased gas costs associated with discontinued operations that were not properly identified and eliminated when discontinued operations were segregated from continued operations for the years ended December 31, 2009, 2008, 2007 and 2006.

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        The table should be read together with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Non-GAAP Financial Measures

        We include the following non-GAAP financial measures: adjusted EBITDA from continuing operations and gross operating margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with generally accepted accounting principles, or GAAP.

        We define adjusted EBITDA from continuing operations as net income plus interest expense, provision for income taxes and depreciation and amortization expense, impairments, stock-based compensation, loss on extinguishment of debt, (gain) loss on noncash derivatives, minority interest and certain severance and exit expenses; less (income) loss from discontinued operations and gain on sale of assets related to discontinued operations. Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

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



•

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



•

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



•

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

        Adjusted EBITDA from continuing operations is one of the critical inputs into the financial covenants within our credit facility. The rates we pay for borrowings under our credit facility are determined by the ratio of our debt to adjusted EBITDA. The calculation of these ratios allows for further adjustments to adjusted EBITDA for recent acquisitions and dispositions. In addition, we have established a target over the next couple of year of achieving a ratio of total debt to adjusted EBITDA of less than 4.0 to 1.0.

        Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA in the same manner.

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

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        Reconciliation of adjusted EBITDA to net income (loss):

        We define gross operating margin, generally, as revenues minus cost of sales. We present gross operating margin by segment in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations." We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because our business is generally to purchase and resell natural gas for a margin or to gather, process, transport or market natural gas and NGLs for a fee. Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating gross operating margin because we separately evaluate commodity volume and price changes in these margin amounts. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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        The following table provides a reconciliation of gross operating margin to operating income (in thousands):

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in this report.

Overview

        We are a Delaware limited partnership formed on July 12, 2002 to indirectly acquire substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. Our primary focus is on the gathering, processing, transmission and marketing of natural gas and NGLs, which we manage as regional reporting segments of midstream activity. Our geographic focus is in the North Texas Barnett shale (NTX) and in Louisiana which has two reportable business segments (the LIG and the south Louisiana processing and NGL assets, or PNGL). We manage our operations by focusing on gross operating margin because our business is generally to purchase and resell natural gas for a margin, or to gather, process, transport or market natural gas and NGLs for a fee. We define gross operating margin as operating revenue minus cost of purchased gas and NGLs.

        Our gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, and the volumes of NGLs handled at our fractionation facilities. We generate revenues from four primary sources:

•

purchasing and reselling or transporting natural gas on the pipeline systems we own;



•

processing natural gas at our processing plants;



•

fractionating and marketing the recovered NGLs; and



•

providing compression services.

        We generally gather or transport gas owned by others through our facilities for a fee, or we buy natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transport and resell the natural gas at the market index. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements.

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When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as our margin. Changes in the basis spread can increase or decrease our margins.

        One contract (the "Delivery Contract") has a term to 2019 that obligates us to supply approximately 150,000 MMBtu/d of gas. At the time that we entered into the Delivery Contract in 2008, we had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract. Our agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of our sales price for such gas less certain fees and costs. Accordingly, we were initially able to generate a positive margin under the Delivery Contract. However, since entering into the Delivery Contract, there has been both (1) a reduction in the gas available under our supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to East Coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract. Due to these factors, we have had to purchase a portion of the gas to fulfill our obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

        We have recorded a loss of approximately $8.4 million during the year ended December 31, 2010 on the Delivery Contract. We currently expect that we will record a loss of approximately $10.0 million to $14.0 million on the Delivery Contract for the year ending December 31, 2011. This estimate is based on forward prices, basis spreads and other market assumptions as of year end 2010. These assumptions are subject to change if market conditions change during 2011, and actual results under the Delivery Contract in 2011 could be substantially different from year end 2010 estimates, which may result in a greater loss than currently estimated.

        We also realize gross operating margins from our processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements our margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of relatively high liquids prices. Under fixed-fee based contracts our margins are driven by throughput volume. See "—Commodity Price Risk."

        Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges, and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.

        Our general and administrative expenses are dictated by the terms of our partnership agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

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Business Strategy

        Our business strategy will focus on increasing our distributable cash flow. Key elements of our strategy will include the following:

•

Undertake selective construction and expansion opportunities on our existing systems.  We intend to leverage our existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for our gathering, transmission, processing and marketing services.



•

Capitalize on our NGL capabilities.  We believe there are near-term growth opportunities for our NGL business based on our ability to increase the utilization of our asset infrastructure which has excess capacity. We are targeting projects that create incremental stable fee-based income from our NGL fractionation business.



•

Pursue accretive acquisitions or construction of facilities in new areas.  We will also consider the acquisition and construction of facilities and systems in new areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas that lack midstream infrastructure to process and/or transport the natural gas.



•

Focus on operational excellence.  We continue to operate our existing asset base to maximize cost efficiencies, provide flexibility for our customers and provide reliable capacity for our customers. We will continue to focus on safety, environmental integrity, innovation and customer service.

Asset Dispositions

        During the past two years, we have repositioned our business through asset dispositions, debt restructuring and improving existing system profitability. These transactions and our improved profitability allowed us to resume distributions to our common unit holders in the third quarter of 2010. We believe the resumption of our distribution is an important milestone in accessing the capital markets to support our future growth strategies.

        Historically, we have operated two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the North Texas Barnett Shale area, and in Louisiana and Mississippi.

        In February 2009, we sold our Oklahoma assets; in August 2009 we sold our Alabama, Mississippi and south Texas Midstream properties; and in October 2009 we sold our Treating assets.

Commodity Price Risk

        We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. For the year ended December 31, 2010 approximately 10.6% of our processed gas arrangements, based on volume, was processed under percent of liquids (POL) contracts. A significant volume of inlet gas at our south Louisiana and north Texas processing plants is settled under POL agreements. Under these contracts we receive a fee in the form of a percentage of the liquids recovered and the producer bears all the costs of the natural gas volumes lost ("shrink"). Accordingly, our revenues under these contracts are directly impacted by the market price of NGLs.

        We also realize processing gross margins under processing margin (margin) contracts. For the year ended December 31, 2010 approximately 12.9% of our processed gas arrangements, based on volume, was processed under margin contracts. We have a number of margin contracts on our Plaquemine and Gibson processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas shrink and the cost of fuel

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used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. Our margins from these contracts can be negative during periods of high natural gas prices relative to liquids prices.

        We are also indirectly exposed to commodity prices due to the negative impacts on production and the development of production of natural gas and NGLs connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products will reduce the demand for our services and volumes on our systems.

        In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, prices of natural gas in 2010 were below the market price realized throughout most of 2009 while prices for oil and NGLs were higher than 2009 market prices. Crude oil prices (based on the New York Mercantile Exchange (the "NYMEX") futures daily close prices for the prompt month) in 2010 ranged from a low of $68.01 per Bbl in May 2010 to a high of $91.51 per Bbl in December 2010. Weighted average NGL prices in 2010 (based on the Oil Price Information Service (OPIS) Napoleonville daily average spot liquids prices) ranged from a low of $0.84 per gallon in July 2010 to a high of $1.23 per gallon in January 2010. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2010 ranged from a high of $7.51 per MMBtu in January 2010 to a low of $3.18 per MMBtu in October 2010.

        Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas we gather and process. The volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. For a discussion of our risk management activities, please read "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

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Results of Operations

        Set forth in the table below is certain financial and operating data for the periods indicated, which excludes financial and operating data deemed discontinued operations. We manage our operations by focusing on gross operating margin which we define as operating revenue minus cost of purchased gas and NGLs as reflected in the table below.

Year ended December 31, 2010 Compared to Year ended December 31, 2009

        Gross Operating Margin.    Gross operating margin was $338.3 million for the year ended December 31, 2010 compared to $311.2 million for the year ended December 31, 2009, an increase of $27.1 million, or 8.7%. The increase was due to higher margins on our gathering and transmission

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throughput volume, as well as a favorable NGL market throughout the year. The following provides additional details regarding this change in gross operating margins:

•

The LIG segment contributed gross operating margin growth of $16.6 million for the year ended December 31, 2010 over the same period in 2009. The gathering and transmission assets generated approximately $11.6 million of gross operating margin growth primarily due to improved pricing and higher volumes on the northern part of the system. The improved processing environment contributed to a gain in the gross operating margins for the LIG processing plants for the period. The Plaquemine and Gibson plants had gross operating margin gains of $2.9 million and $2.0 million, respectively.



•

The NTX segment had gross operating margin improvement of $2.8 million for the year ended December 31, 2010. A $3.7 million charge associated with an adverse arbitration award was included in 2009. Increased losses of $4.5 million under a certain supply agreement were offset by improvements in a number of areas that enhanced liquids recoveries and unit margins, in addition to better processing margins.



•

The improved processing and NGL marketing environment contributed to a $13.7 million increase in gross operating margin for the PNGL segment for the comparative periods. Fractionation and marketing activity generated a gross operating margin increase of approximately $10.0 million. In addition to the improved marketing environment, the inlet volume supplied to the fractionators was significantly increased through deliveries from rail cars and trucks. The Eunice and Pelican processing plants contributed gross operating margin increases of $2.9 million and $2.4 million, respectively. The Sabine Pass plant had a gross operating margin decline of $2.2 million due to a decrease in inlet volumes.



•

The corporate segment reported a gross operating margin decrease of approximately $6.0 million for the year ended December 31, 2010 over the same period in 2009. The Crosstex Pipeline system in east Texas which was sold in the first quarter of 2010, created a negative gross operating margin variance of $5.8 million when compared to the prior period.

        Operating Expenses.    Operating expenses were $105.1 million for the year ended December 31, 2010 compared to $110.4 million for the year ended December 31, 2009, a decrease of $5.3 million, or 4.8%. The decrease is primarily the result of the following:

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We purchased the Eunice plant in late 2009 that resulted in $9.5 million decrease in rent expense;



•

We sold our east Texas system which was not considered discontinued operations early in 2010 and this resulted in $3.9 million of reduced operating expenses;



•

We were successful in renegotiating our existing compressor leases that resulted in $1.3 million of cost savings;



•

We have expanded our Louisiana operations which caused operating expenses to increase by approximately $4.9 million;



•

We experienced an increase in our operating expenses of $1.8 million related to ad valorem taxes, insurance costs and regulatory costs; and



•

Our repairs and maintenance costs increased operating expenses by $3.3 million in 2010 over 2009.

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        General and Administrative Expenses.    General and administrative expenses were $48.4 million for the year ended December 31, 2010 compared to $59.9 million for the year ended December 31, 2009, a decrease of $11.4 million, or 19.1%. The decrease is primarily a result of the following:

•

We reduced our workforce in 2009 which resulted in a decrease of $9.4 million in labor and benefits; and



•

We lowered our legal and professional costs by $2.4 million in 2010.

        Gain on sale of Property from Continuing Operations.    Gains on sale of property were $13.9 million for the year ended December 31, 2010 compared to $0.7 million for the year ended December 31, 2009. The gain on sale of property for the year ended December 31, 2010 was related to the sale of our east Texas assets in January 2010.

        Gain/Loss on Derivatives.    We had a loss on derivatives of $9.1 million for the year ended December 31, 2010 compared to a gain of $3.0 million for the year ended December 31, 2009. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):