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

FORM 10-K

Commission file number: 000-50536

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

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

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 voting and non-voting common equity held by non-affiliates of the registrant was approximately $213,009,960 on June 30, 2010, based on $6.41 per share, the closing price of the Common Stock as reported on The NASDAQ Global Select Market on such date.

         At February 11, 2011, there were 47,054,493 common shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

         Portions of the Registrant's Proxy Statement relating to its 2011 Annual Stockholders' Meeting to be filed with the Securities and Exchange Commission are incorporated by reference herein into Part III of this Report.

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DESCRIPTION

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CROSSTEX ENERGY, INC.

PART I

Item 1.    Business

General

        Crosstex Energy, Inc. is a Delaware corporation, formed in April 2000. We completed our initial public offering in January 2004. Our shares of common stock are listed on the NASDAQ Global Select Market under the symbol "XTXI". 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 term "Crosstex Energy, Inc." as well as the terms "our," "we," and "us," or like terms, are sometimes used as references to Crosstex Energy, Inc. and its consolidated subsidiaries. References in this report to "Crosstex Energy, L.P.," the "Partnership," "CELP" or like terms refer to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. together with its consolidated subsidiaries.

        Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs. These partnership interests consist of the following:

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16,414,830 common units representing an aggregate 25.0% limited partner interest in the Partnership as of December 31, 2010, and



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100.0% ownership interest in Crosstex Energy GP, LLC, the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

        Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership's business or to provide for future distributions.

        The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

        During 2009, the Partnership's ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions in 2009. The Partnership resumed making quarterly distributions to its common unitholders during the third quarter of 2010. In November 2010 and February 2011, the Partnership paid quarterly distributions of $0.25 and $0.26 per unit related to the third and fourth quarters of 2010, respectively. Our share of the distributions with respect to our limited and general partner interests in the Partnership totaled $4.4 million for the third quarter of 2010 and $4.7 million for the fourth quarter of 2010.

        Since our cash flows consist almost exclusively of distributions from the Partnership, we also ceased making dividends to our stockholders during 2009. With the resumption of distributions from the Partnership in 2010, we also resumed quarterly dividend payments to our common stockholders and

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paid quarterly dividends of $0.07 and $0.08 per share in November 2010 and February 2011, respectively. We intend to continue to pay dividends to our stockholders on a quarterly basis equal to the cash we receive, if any, from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

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federal income taxes, which we are required to pay because we are taxed as a corporation;



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the expenses of being a public company;



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other general and administrative expenses;



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capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner's 2.0% general partner interest; and



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cash reserves our board of directors believed were prudent to maintain.

        Our ability to pay dividends is limited by the Delaware General Corporation Law, which provides that a corporation may only pay dividends out of existing "surplus," which is defined as the amount by which a corporation's net assets exceeds its stated capital. While our ownership of the general partner and the common units of the Partnership are included in our calculation of net assets, the value of these assets may decline to a level where we have no "surplus," thus prohibiting us from paying dividends under Delaware law.

        So long as we own the Partnership's general partner, under the terms of an omnibus agreement with the Partnership we are prohibited from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of a majority of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. The Partnership may elect to forego an opportunity for several reasons, including:

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the nature of some or all of the target's assets or income might affect the Partnership's ability to be taxed as a partnership for federal income tax purposes;



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the board of directors of Crosstex Energy GP, LLC, the general partner of the Partnership, may conclude that some or all of the target assets are not a good strategic opportunity for the Partnership; or



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the seller may desire equity, rather than cash, as consideration or may not want to accept the Partnership's units as consideration.

        We have no present intention of engaging in additional operations or pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement, although we may decide to pursue them in the future, either alone or in combination with the Partnership. In the event that we pursue the types of opportunities that we are permitted to pursue under the omnibus agreement, our board of directors, in its sole discretion, may retain all, or a portion of, the cash distributions we receive on our partnership interests in the Partnership to finance all, or a portion of, such transactions, which may reduce or eliminate dividends paid to our stockholders.

CROSSTEX ENERGY, L.P.

        Crosstex Energy, L.P. is an independent midstream energy company engaged in the gathering, transmission, processing and marketing of natural gas and NGLs. It connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. It purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other

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marketers and pipelines. It operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee arrangements. In addition, it purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee. 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 = gallons
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid

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        Capacity volumes for the Partnership's 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. Fractionation volumes are measured based on physical volume and stated in gallons (Gal).

Operations of the Partnership

        The Partnership focuses on the gathering, processing, transmission and marketing of natural gas and NGLs, which the Partnership manages as regional reporting segments. The Partnership's 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). Its 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 located in two primary regions: north Texas and Louisiana. Its 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. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Its processing plants remove NGLs from a natural gas stream and its 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.

        The Partnership assets include the following:

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North Texas Assets.  The North Texas Assets are comprised of gathering, processing and transmission assets serving producers active in the Barnett Shale. The 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 of approximately 730,000 MMBtu/d for the year ended December 31, 2010. The Partnership's 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. Transmission assets consist 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.



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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, Plaquemine and Gibson, 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.



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South Louisiana Processing and NGL Assets.  The Partnership's south Louisiana natural gas processing and liquids assets include approximately 2.0 Bcf/d of processing capacity,

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64,000 Bbls/d of fractionation capacity, 2.4 million barrels of underground storage and approximately 440 miles of 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.

Business Strategy

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

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Undertake selective construction and expansion opportunities on the Partnership's existing systems.  The Partnership intends to leverage its existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for its gathering, transmission, processing and marketing services. The Partnership has two expansion projects that are underway in north Texas and scheduled for completion near the end of the first quarter of 2011. The Partnership is 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. The Partnership's second project involves a 15 mile expansion of its 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.



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Capitalizing on the Partnership's NGL capabilities.  The Partnership believes there are near-term growth opportunities for its NGL business based on its ability to increase the utilization of its asset infrastructure which has excess capacity. The Partnership is targeting projects that create incremental stable fee-based income from its NGL fractionation business. The Partnership sees 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. The Partnership is currently offering producers in these regions an interim solution by transporting NGLs via rail or truck to its fractionators in Louisiana. During 2010, the Partnership was handling approximately 7,300 Bbls/d under these type of arrangements. The Partnership has initiated construction on a project to bring 15,000 Bbls/d of idle fractionation capacity at its 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

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approximately $3.0 million and will provide capacity for continued growth from its NGL rail aggregation business.

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Pursue accretive acquisitions or construction of facilities in new areas.  The Partnership 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. The Partnership believes its existing infrastructure, personnel, producer and consumer relationships, and construction experience, including experience in large shale developments, provide the Partnership with a competitive advantage for such expansion opportunities. The Partnership believes its 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. The Partnership intends to use its 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.



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

Recent Developments

        The Partnership resumed making quarterly distributions to its common unitholders during the third quarter of 2010. In November 2010, the Partnership paid a quarterly distribution of $0.25 per unit related to the three months ended September 30, 2010. The Partnership 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. The Partnership believes the resumption of its distributions is an important milestone in accessing the capital markets to support its future growth strategies.

        Prior to December 31, 2010, the Partnership's general partner was Crosstex GP, L.P., and Crosstex Energy GP, LLC, as the general partner of Crosstex Energy GP, L.P., managed the Partnership's 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.

Partnership Assets

        North Texas Assets.    The Partnership's 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 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, the Partnership 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

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Chief and acquired by Devon simultaneously with the 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, the Partnership began expanding its north Texas gathering system.

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Gathering System.  Since the date of the acquisition through December 31, 2010, the Partnership has expanded its gathering system and connected in excess of 600 new wells to its 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 capacity on its 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. The Partnership has two expansion projects that are underway on its 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 its north Texas gathering system. The Partnership is 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.



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Processing Facilities.  Since 2006, the Partnership has constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including its Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, its Azle plant, which is a 50 MMcf/d cryogenic processing plant and its 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.

        The Partnership has budgeted approximately $30.0 million for continued development of its north Texas assets during 2011, primarily related to its 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, its 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 the Partnership is connecting to its south Louisiana NGL system in conjunction with the restart of its 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, the Partnership expanded its 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. The Partnership's 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 the Partnership 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. The Partnership continued the expansion of its 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. The Partnership has long-term firm transportation

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agreements subscribing to all of the incremental capacity added during 2009 and 2010. In addition, the Partnership added compression during 2009 between the southern portion of its Crosstex LIG system and the northern expansion of its Crosstex LIG system, which increased the capacity to move gas from the north LIG system to its 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.

        South Louisiana Processing and NGL Assets.    The Partnership's 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:

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NGL Assets.  The Partnership's NGL assets include its Eunice processing plant and fractionation facility, its Riverside fractionation plant, its Cajun Sibon pipeline system and its Napoleonville storage facility. The Partnership had excess capacity on its NGL assets during 2008 and 2009 and has made numerous operational changes and reconfigured operations to manage the lower utilization and reduce operating costs. During 2010, the Partnership has increased its focus on its 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, the Partnership believes NGL supplies will continue to grow so it expects to see continued growth in its NGL business which will increase utilization of its facilities.



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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 the Partnership's Cajun Sibon pipeline system to its Riverside plant for fractionation. The Partnership plans to restart its 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, the Partnership will connect the Plaquemine fractionator into the Partnership's NGL system for increased operational flexibility. This expansion will give the Partnership operational flexibility, increased fractionation capacity, and the ability to capture new NGL-related business. The Partnership expects 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 the Partnership's NGL rail aggregation business.



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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

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storage capacity of approximately 102,000 barrels. The Partnership has recently completed a project to reduce the fuel requirements at this facility by 15.0%.

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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.



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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. The Partnership has recently established an interconnection with the LIG pipeline for optimization of processing opportunities.



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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.



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Blue Water Gas Processing Plant.  The Partnership owns a 59.27% interest in the Blue Water gas processing plant and operates 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 the Partnership's 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 the Partnership's 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.

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

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Industry Overview

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

        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

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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.

Balancing of Supply and Demand

        As the Partnership purchases natural gas, it establishes a margin normally by selling natural gas for physical delivery to third-party users. It can also use over-the-counter derivative instruments or enter into a future delivery obligation under futures contracts on the NYMEX. Through these transactions, the Partnership seeks to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Its 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. The Partnership faces strong competition in obtaining natural gas supplies and in the marketing and transportation of natural gas and NGLs. Its 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 the Partnership's competitors offer more services or have greater financial resources and access to larger natural gas supplies than it does. The Partnership's competition differs in different geographic areas.

        In marketing natural gas and NGLs, the Partnership has 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 the Partnership's marketing operations.

        The Partnership faces 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 its competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. The Partnership's competition differs by region and by the nature of the business or the project involved.

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Natural Gas Supply

        The Partnership's transmission pipelines have connections with major interstate and intrastate pipelines, which it believes have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of its gathering systems, the Partnership evaluates 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, the Partnership believes that there should be adequate natural gas supply to recoup its investment with an adequate rate of return. The Partnership does not routinely obtain independent evaluations of reserves dedicated to its systems due to the cost and relatively limited benefit of such evaluations. Accordingly, it does not have estimates of total reserves dedicated to its systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

        The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the purchase and resale of gas exposes it 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 overall profitability.

        During the year ended December 31, 2010, the Partnership had three customers that represented greater than 10.0% individually of its revenue. Two customers in the Partnership's LIG segment represented 14.5% and 10.6% of its consolidated revenue. One customer in the Partnership's NTX segment represented 10.2% of its consolidated revenue. While these customers represents a significant percentage of consolidated revenues, the loss of these customers would not have a material impact on results of operations because the gross operating margins received from transactions with these customers are not material to the Partnership's total gross operating margin and the Partnership believes 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.    The Partnership does not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or FERC, does not directly regulate its operations under the National Gas Act, or NGA. However, FERC's regulation of interstate natural gas pipelines influences certain aspects of the Partnership's business and the market for its 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 the Partnership does not own any interstate pipelines, it does transport gas in interstate commerce. The rates, terms and conditions of service under which the Partnership transports natural gas in its pipeline systems in interstate commerce are subject to FERC jurisdiction under Section 311 of

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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 the Partnership's 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.    The Partnership's 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. The Partnership owns a number of natural gas pipelines that it believes 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.

        The Partnership is 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 the Partnership sells natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Its 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. The Partnership cannot predict the ultimate impact of these regulatory changes on its natural gas marketing operations but does not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.

Environmental Matters

        General.    The Partnership's 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 the Partnership's overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities. Included in the Partnership's construction and operation costs are capital cost items necessary

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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 the Partnership currently holds all material governmental approvals required to operate its major facilities. As part of the regular overall evaluation of its operations, the Partnership has implemented procedures to review and update governmental approvals as necessary. We believe that the Partnership's 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 its 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 the Partnership's possible future operations, and we cannot assure you that the Partnership 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, the Partnership may be unable to pass on those cost increases to its customers. A discharge of hazardous substances or wastes into the environment could, to the extent losses related to the event are not insured, subject the Partnership 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 to claims made by neighboring landowners and other third parties for personal injury or damage to natural resources or property. The Partnership 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 the Partnership's 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, the Partnership may generate wastes that may fall within the definition of a "hazardous substance." In addition, there are

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other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, the Partnership 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. The Partnership has not received any notification that it may be potentially responsible for cleanup costs under CERCLA or any analogous federal or state laws.

        The Partnership also generates, 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 it 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 the Partnership's capital expenditures or plant operating expenses or otherwise impose limits or restrictions on its production and operations.

        The Partnership currently owns or leases, and has in the past owned or leased, and in the future 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 the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom the Partnership 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 properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership 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.    The Partnership's 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 the Partnership's facilities, and impose various controls together with monitoring and reporting requirements. Pursuant to these laws and regulations, the Partnership 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. The Partnership 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 the Partnership's financial condition or operating results, and the requirements are not expected to be more burdensome to the Partnership 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

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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 the Partnership's 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 the Partnership's 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 the Partnership 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 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 its operations and its 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 the Partnership conducts business could adversely affect the demand for the products it stores, transports, and processes, and depending on the particular program adopted could increase the costs of its operations, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its greenhouse gas emissions, pay any taxes related to its greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. The Partnership may be unable to recover any such lost revenues or increased costs in the rates it charges its customers, and any such recovery may depend on events beyond its 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 the Partnership's revenues or increases

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in its expenses as a result of climate control initiatives could have adverse effects on its 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. The Partnership believes that it is 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 its 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 the Partnership's customers, particularly in Barnett Shale and Haynesville Shale regions of its 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 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 the Partnership's 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 the Partnership's 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 the

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Partnership's customers move through its gathering systems which would materially adversely affect its revenues and results of operations.

        Employee Safety.    The Partnership is 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. The Partnership believes that its 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.    The Partnership's 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 the Partnership's pipelines in Texas under its own pipeline integrity management rules. The Texas rule includes certain transmission based upon pipeline diameter and operating pressures. The Partnership believes that its pipeline operations are in substantial compliance with applicable PHMSA and PIM requirements; however, due to the possibility 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 the Partnership's 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 the Partnership's 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, the Partnership (through its subsidiaries) employed approximately 469 full-time employees. Approximately 173 of the employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. The Partnership is not party to any collective bargaining agreements, and has not had any significant labor disputes in the past. We believe that the Partnership has good relations with its employees.

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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 pay dividends to our shareholder and the trading price of our common share 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.

Our cash flow consists almost exclusively of distributions from Crosstex Energy, L.P.

        Our only cash-generating assets are our partnership interests in Crosstex Energy, L.P. Our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners. Prior to 2009, we received quarterly distributions from the Partnership with the last distribution for the fourth quarter of 2008 received in February 2009. During 2009, the Partnership's ability to distribute available cash was contractually restricted by the terms of its credit facility and it ceased making distributions. The Partnership resumed making quarterly distributions to its common unitholders during the last half of 2010.

        The amount of cash that the Partnership can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

•

the amount of natural gas transported in its gathering and transmission pipelines;



•

the level of the Partnership's processing operations;



•

the fees the Partnership charges and the margins it realizes for its services;



•

the price of natural gas;



•

the relationship between natural gas and NGL prices; and



•

its level of operating costs;

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

•

the level of capital expenditures the Partnership makes;



•

the cost of acquisitions, if any;



•

its debt service requirements;



•

fluctuations in its working capital needs;



•

its ability to make working capital borrowings under its bank credit facility to pay distributions;



•

prevailing economic conditions; and



•

the amount of cash reserves established by the general partner in its sole discretion for the proper conduct of its business.

        Because of these factors, the Partnership may not be able, or may not have sufficient available cash to pay distributions to unitholders each quarter. Furthermore, you should also be aware that the amount of cash the Partnership has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function

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of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.

We are largely prohibited from engaging in activities that compete with the Partnership.

        So long as we own the general partner of the Partnership, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. This exception for competitive activities is relatively limited. Although we have no current intention of pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement such as competitive opportunities that the Partnership declines to pursue or permitted activities that are not competition with the Partnership, the provisions of the omnibus agreement may, in the future, limit activities that we would otherwise pursue.

In our corporate charter, we have renounced business opportunities that may be pursued by the Partnership or by certain stockholders.

        In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to:

•

persons who are officers or directors of the company or who, on October 1, 2003, were, and at the time of presentation are, stockholders of the company (or to persons who are affiliates or associates of such officers, directors or stockholders), if the company is prohibited from participating in such opportunities by the omnibus agreement; or



•

any investment fund sponsored or managed by Yorktown Partners LLC, including any fund still to be formed, or to any of our directors who is an affiliate or designate of these entities.

        As a result of this renunciation, these officers, directors and stockholders should not be deemed to be breaching any fiduciary duty to us if they or their affiliates or associates pursue opportunities presented as described above.

Although we control the Partnership, the general partner owes fiduciary duties to the Partnership and the unitholders.

        Conflicts of interest exist and may arise in the future as a result of the relationship between us and our affiliates, including the general partner, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of Crosstex Energy GP, LLC have fiduciary duties to manage the general partner in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and its limited partners. The board of directors of Crosstex Energy GP, LLC will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders.

        For example, conflicts of interest may arise in the following situations:

•

the allocation of shared overhead expenses to the Partnership and us;

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•

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and the Partnership, on the other hand, including obligations under the omnibus agreement;



•

the determination of the amount of cash to be distributed to the Partnership's partners and the amount of cash to be reserved for the future conduct of the Partnership's business;



•

the determination whether to make borrowings under the capital facility to pay distributions to partners; and



•

any decision we make in the future to engage in activities in competition with the Partnership as permitted under our omnibus agreement with the Partnership.

If the general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of the Partnership, its value, and therefore the value of our common stock, could decline.

        The general partner may make expenditures on behalf of the Partnership for which it will seek reimbursement from the Partnership. In addition, under Delaware partnership law, the general partner, in its capacity as the general partner of the Partnership, 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 the general partner. To the extent the general partner incurs obligations on behalf of the Partnership, it is entitled to be reimbursed or indemnified by the general partner. In the event that the Partnership is unable or unwilling to reimburse or indemnify the general partner, the general partner may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common stock.

Risks Inherent in the Partnership's Business

The Partnership's profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile.

        The Partnership is subject to significant risks due to fluctuations in commodity prices. The Partnership is directly exposed to these risks primarily in the gas processing component of its business. For the year ended December 31, 2010 approximately 10.6% of its processed gas arrangements, based on volume, was processed under percent of liquids (POL) contracts. Under these contracts the Partnership receives 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, the Partnership's revenues under these contracts is directly impacted by the market price of NGLs.

        The Partnership also realizes processing gross margins under processing margin (margin) contracts. For the year ended December 31, 2010 approximately 12.9% of the Partnership's processed gas arrangements, based on volume, was processed under margin contracts. The Partnership has a number of margin contracts on the Partnership's Plaquemine and Gibson processing plants. Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and it makes 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. The Partnership's margins from these contracts can be negative during periods of high natural gas prices relative to liquids prices.

        The Partnership is 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 its assets and on its margins for transportation between certain market centers. Low prices for these products will reduce the demand for the Partnership's services and volumes on its systems.

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        In the past, the prices of natural gas and NGLs have been extremely volatile and the Partnership expects 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 the Partnership's 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:

•

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;



•

the availability of imported oil, natural gas and NGLs;



•

international demand for oil and NGLs;



•

actions taken by foreign oil and gas producing nations;



•

the availability of local, intrastate and interstate transportation systems;



•

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

The Partnership's substantial indebtedness could limit its flexibility and adversely affect its financial health.

        The Partnership has a substantial amount of indebtedness. As of December 31, 2010, the Partnership 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. The Partnership also has a bank credit facility with a borrowing capacity of $420.0 million that had

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approximately $86.6 million of letters of credit outstanding, leaving available capacity of $333.4 million as of December 31, 2010.

        The Partnership's substantial indebtedness could limit its flexibility and adversely affect its financial health. For example, it could:

•

make the Partnership more vulnerable to general adverse economic and industry conditions;



•

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



•

limit the Partnership's flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and



•

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

        In addition, the Partnership's ability to make scheduled payments or to refinance its obligations depends on its successful financial and operating performance. The Partnership cannot assure you that its operating performance will generate sufficient cash flow or that its capital resources will be sufficient for payment of its indebtedness obligations in the future. The Partnership's 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 its control.

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

The Partnership may not be able to access new capital to fund its acquisition and growth strategies which could impair its 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 its 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, the Partnership cannot be certain that new debt or equity financing will be available to it on acceptable terms or at all. Without adequate funding, the Partnership may be unable to execute its 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 the Partnership's revenues and results of operations. Further, the Partnership's customers may increase collateral requirements from it, including letters of credit which reduce available borrowing capacity, or reduce the business they transact with the Partnership to reduce their credit exposure.

Due to the Partnership's lack of asset diversification, adverse developments in its gathering, transmission, processing and NGL services businesses would materially impact its financial condition.

        The Partnership relies exclusively on the revenues generated from its gathering, transmission, processing and NGL services businesses and as a result its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to its lack of asset diversification, an adverse

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development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if the Partnership maintained more diverse assets.

The Partnership may not be successful in balancing its purchases and sales.

        The Partnership is a party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that the Partnership has under contract may decline due to reduced drilling or other causes and it 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 the Partnership's purchases and sales not to be balanced. If the Partnership's purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.

        The Partnership makes 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 the Partnership's margins or even result in losses. For example, the Partnership is a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/day of gas. The Partnership buys gas for this contract on several different production-area indices on its NTP and sells the gas into a different market area index. For the year ended December 31, 2010 the Partnership has recorded a loss of approximately $8.4 million on this contract, and it currently expects that it 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."

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

        The Partnership's 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 its natural gas gathering systems and asset utilization rates at its processing plants and to fulfill its current sales commitments, the Partnership must continually contract for new natural gas supplies. The Partnership may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting its ability to connect new wells to its gathering facilities include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near its gathering systems. If the Partnership is unable to maintain or increase the throughput on its systems by accessing new natural gas supplies to offset the natural decline in reserves, the Partnership's business and financial results could be materially, adversely affected. In addition, the Partnership's future growth will depend in part upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in the currently connected supplies.

        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,

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reducing supplies of natural gas available to the Partnership's systems. The Partnership has 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 its principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on the Partnership's results of operations and financial position.

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

The Partnership is vulnerable to operational, regulatory and other risks due to its concentration of assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.

        The Partnership's operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because it has a significant portion of its assets located in these two areas. The Partnership's concentration of activity in Louisiana and the Gulf of Mexico makes it more vulnerable than many of its 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 the Partnership's operations could experience the same condition at the same time, these conditions could have a relatively greater impact on its results of operations than they might have on other midstream companies who have operations in more diversified geographic areas.

The Partnership's use of derivative financial instruments does not eliminate its 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 its income.

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

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        Even though monitored by management, the Partnership's hedging activities may fail to protect it and could reduce its earnings and cash flow. The Partnership's 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;



•

the Partnership's 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 the Partnership seeks protection. For example:



•

the duration of a hedge may not match the duration of the risk against which the Partnership seeks protection;



•

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



•

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

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

        The NGL products the Partnership produces 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 the Partnership handles or reduce the fees the Partnership charges for its services. The Partnership's 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 the Partnership accesses for any of the reasons stated above could adversely affect demand for the services the Partnership provides as well as NGL prices, which would negatively impact its results of operations and financial condition.

Growing the Partnership's business by constructing new pipelines and processing facilities subjects it 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 the Partnership intends to grow its business is through the construction of additions to its 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 its expectations. Generally, the Partnership may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Moreover, it may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. The Partnership may also rely on estimates of proved reserves in its 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 its expected investment return, which could adversely affect the Partnership's results of operations and financial condition. In addition, the Partnership faces 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 the Partnership expands its operations into more urban, populated areas such as the Barnett Shale.

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

        The Partnership's ability to grow depends, in part, on its ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If the Partnership is unable to make accretive acquisitions either because it is (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then its future growth and its ability to increase distributions will be limited.

        From time to time, the Partnership may evaluate and seek to acquire assets or businesses that it believes complement its existing business and related assets. The Partnership may acquire assets or businesses that it plans 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 the Partnership's 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 the Partnership's operations and cash flows. If the Partnership consummates any future acquisition, its 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 the Partnership will consider in determining the application of these funds and other resources.

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

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

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

•

incur or guarantee additional indebtedness or issue preferred stock;



•

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



•

make investments;

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•

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



•

engage in transactions with its affiliates;



•

sell assets, including equity securities of its subsidiaries;



•

consolidate or merge;



•

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 it conducts.

        In addition, the Partnership's credit facility requires it to satisfy and maintain specified financial ratios and other financial condition tests. Its ability to meet those financial ratios and tests can be affected by events beyond its control, and it cannot assure you that it will meet those ratios and tests.

        A breach of any of these covenants could result in an event of default under the Partnership's 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 the Partnership is unable to repay the accelerated debt under its senior secured credit facility, the lenders under senior secured credit facility could proceed against the collateral granted to them to secure that indebtedness. The Partnership has pledged substantially all of its assets as collateral under its senior secured credit facility. If indebtedness under its senior secured credit facility or indentures is accelerated, it cannot assure you that it 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 its ability to finance future operations or capital needs or to engage in other business activities.

The Partnership does not own most of the land on which its pipelines and compression facilities are located, which could disrupt its operations.

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

The Partnership expects to encounter significant competition in any new geographic areas into which the Partnership seeks to expand and its ability to enter such markets may be limited.

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

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

        The renewal or replacement of existing contracts with the Partnership's customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets the Partnership serves. The inability of the Partnership's management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on its profitability.

        In particular, the Partnership's ability to renew or replace its existing contracts with industrial end-users and utilities impacts its profitability. For the year ended December 31, 2010, approximately 49% of its sales of gas that was transported using its 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 the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the basis of price.

The Partnership depends on certain key customers, and the loss of any of its key customers could adversely affect its financial results.

        The Partnership derives a significant portion of its 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, the Partnership would be adversely affected unless it was 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.

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

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

Federal, state or local regulatory measures could adversely affect the Partnership's business.

        The Partnership's 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 the Partnership's 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

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transferred gathering facilities to unregulated affiliates. The Partnership's 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. The Partnership cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        The rates, terms and conditions of service under which the Partnership transports natural gas in its pipeline systems in interstate commerce are subject to FERC regulation under the Section 311 of the Natural Gas Policy Act. Under these regulations, the Partnership is required to justify its rates for interstate transportation service on a cost-of-service basis, every three years. The Partnership's 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 its rates for Section 311 transportation service or intrastate transportation service should be lowered, its business could be adversely affected.

        Other state and local regulations also affect the Partnership's business. The Partnership is subject to some ratable take and common purchaser statutes in the states where it operates. 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 the Partnership's right as an owner of gathering facilities to decide with whom it contracts 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 it operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which the Partnership operates 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 the Partnership conducts 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 its 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. The Partnership's 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. The Partnership expects the costs for compliance with TRRC and DOT regulations to be approximately $1.6 million during 2011. If its pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then it may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

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

The Partnership's business involves hazardous substances and may be adversely affected by environmental regulation.

        Many of the operations and activities of the Partnership's 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 its facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by the Partnership or locations to which the Partnership has 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 the Partnership's facilities or upon or through which its 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 the Partnership's business due to its handling of natural gas and other petroleum substances, air emissions related to its 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 its compliance costs and the cost of any remediation that may become necessary. The Partnership may incur material environmental costs and liabilities. Furthermore, its insurance may not provide sufficient coverage in the event an environmental claim is made against it.

        The Partnership's 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 its 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 its profitability. Changes in laws or regulations could also limit its production or the operation of its assets or adversely affect its ability to comply with applicable legal requirements or the demand for natural gas, which could adversely affect its business and its profitability.

Recent events in the Gulf of Mexico may decrease the supplies of natural gas to the Partnership's 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

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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 the Partnership's operations. The Partnership's 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 its facilities, and may potentially reduce volumes in its NGL marketing business.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by the Partnership's customers, which could adversely impact its revenues by decreasing the volumes of natural gas that it gathers, transports and processes.

        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 the Partnership's revenues and results of operations by decreasing the volumes of natural gas that it gathers, transports and processes.

The Partnership's business involves many hazards and operational risks, some of which may not be fully covered by insurance.

        The Partnership's 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 the Partnership's related operations. The Partnership is

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not fully insured against all risks incident to its business. In accordance with typical industry practice, the Partnership does not have any property insurance on any of its underground pipeline systems that would cover damage to the pipelines. The Partnership is 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 the Partnership's operations and financial condition.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership's ability to hedge risks associated with its 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 the Partnership, that participate in that market. The new legislation was signed into law by the President on 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 the Partnership to comply with margin requirements in connection with its derivative activities, although the application of those provisions to the Partnership is uncertain at this time. The CFTC has proposed regulations that may provide to the Partnership the certainty that it 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 the Partnership, 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 the Partnership encounters, and reduce its ability to monetize or restructure its existing derivative contracts. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its 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. The Partnership's 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 the Partnership's 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 the Partnership provides.

        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,

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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, the Partnership's equipment and operations could require the Partnership to incur additional costs to reduce emissions of GHGs associated with its operations, could adversely affect its performance of 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 the Partnership gathers, processes or otherwise handles in connection with its services.

The Partnership typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering pipeline systems; therefore, volumes of natural gas on its systems in the future could be less than it anticipates.

        The Partnership typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to its gathering systems is less than it anticipates and it is unable to secure additional sources of natural gas, then the volumes of natural gas transported on its gathering systems in the future could be less than anticipated. A decline in the volumes of natural gas on its systems could have a material adverse effect on its 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 the Partnership's results of operations and its 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. The Partnership's insurance policies generally excludes acts of terrorism. Such insurance is not available at what the Partnership believes to be acceptable pricing levels.

The Partnership's success depends on key members of its management, the loss or replacement of whom could disrupt its business operations.

        The Partnership depends on the continued employment and performance of the officers of its general partner and key operational personnel. The 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, the Partnership's business operations could be materially adversely affected. The Partnership does not maintain any "key man" life insurance for any officers.

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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 the Partnership's 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. The Partnership has 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 the Partnership's pipeline was built was purchased in fee. The Partnership's processing plants are located on land that the Partnership leases or owns in fee.

        We believe that the Partnership has satisfactory title to all of its rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. The Partnership believes that none of such encumbrances or defects should materially detract from the value of its assets or from its interest in these assets or should materially interfere with their use in the operation of the business.

Item 3.    Legal Proceedings

        Our operations and those of the Partnership are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we or the Partnership 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 the Partnership continues to expand operations into more urban, populated areas, such as the Barnett Shale, it 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.

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        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 stock is listed on The NASDAQ Global Select Market under the symbol "XTXI". Our common stock began trading on January 12, 2004. On February 11, 2011, the closing market price for our common stock was $8.65 per share and there were approximately 10,875 record holders and beneficial owners (held in street name) of the shares of our common stock.

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

        We intend to pay dividends to our stockholders, on a quarterly basis, equal to the cash we receive if any, from distributions from the Partnership, less reserves for expenses, future dividends and other uses of cash, including:

•

federal income taxes, which we are required to pay because we are taxed as a corporation;



•

the expenses of being a public company;



•

other general and administrative expenses;



•

capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner's 2.0% general partner interest; and



•

reserves our board of directors believes prudent to maintain.

        The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Company intends to pay dividends to stockholders and is dependent on receiving a cash distribution from the Partnership. During 2009, the Partnership's ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions in 2009. The Partnership resumed making quarterly distributions to its common unitholders during the third quarter of 2010. In November 2010 and February 2011, the Partnership paid quarterly distributions of $0.25 and $0.26 per unit related to the third and fourth quarters of 2010, respectively. Our share of the distributions with respect to our limited and general partner interests in the Partnership totaled $4.4 million for the third quarter of 2010 and $4.7 million for the fourth quarter of 2010.

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Performance Graph

        The following graph sets forth the cumulative total stockholder return for our common stock, the Standard & Poor's 500 Stock Index, and a peer group of publicly traded partners of publicly traded limited partnerships in the Midstream natural gas, natural gas liquids, propane, pipeline and coal industries from January 1, 2006, the date of our initial public offering, through December 31, 2010. The chart assumes that $18 was invested on January 12, 2004, with dividends reinvested. The peer group includes Atlas Pipeline Holdings, L.P., Alliance Holdings GP, L.P., Energy Transfer Equity, L.P., Nustar GP Holdings, LLC and Penn Virginia GP Holdings, L.P. (Energy Transfer Equity, L.P.'s initial public offering was in February 2006, Alliance Holdings GP, L.P.'s initial public offering was in May 2006, Atlas Pipeline Holdings, L.P.'s initial public offering was in July 2006, Nustar GP Holdings, LLC's initial public offering was in July 2006 and Penn Virginia, GP Holdings, L.P. initial public offering was in December 2006, and it has been assumed that these companies performed in accordance with the peer group average prior to such dates).

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Item 6.    Selected Financial Data

        The following table sets forth selected historical financial and operating data of Crosstex Energy, Inc as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, Inc and have been revised to reflect certain immaterial corrections. The corrections did not impact the Company's operating income and were not material to the 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.

        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: the Partnership's 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 the Partnership's 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. The Partnership's adjusted EBITDA is used as a supplemental performance measure by its management and by external users of its financial statements such as investors, commercial banks, research analysts and others, to assess:

•

financial performance of the Partnership's assets without regard to financing methods, capital structure or historical cost basis;



•

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



•

the Partnership's 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.

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

        The Partnership's 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. The Partnership's 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.

        The Partnership's adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because the Partnership has borrowed money to finance its operations, interest expense is a necessary element of its costs and its ability to generate cash available for distribution. Because the Partnership uses capital assets, depreciation and amortization are also necessary elements of its 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 the Partnership's adjusted EBITDA, to evaluate the Partnership's overall performance.

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        Reconciliation of the Partnership's 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 the Partnership's 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 the Partnership's operation and maintenance expenses. These expenses are largely independent of the volumes the Partnership transports or processes and fluctuates 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

        Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing and marketing of natural gas and NGLs through its subsidiaries. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 16,414,830 common units, representing approximately 25.0% of the limited partner interests in Crosstex Energy, L.P. as of December 31, 2010 and (ii) 100% ownership interest in Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

        Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership's business or to provide for future distributions.

        The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter, and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

        During 2009, the Partnership's ability to distribute available cash was contractually restricted by the terms of its credit facility and it ceased making distributions in 2009. The Partnership resumed making quarterly distributions to its common unitholders during the third quarter of 2010. In November 2010 and February 2011, the Partnership paid quarterly distributions of $0.25 and $0.26 per unit related to the third and fourth quarters of 2010, respectively. Our share of the distributions with respect to our limited and general partner interests in the Partnership totaled $4.4 million for the third quarter of 2010 and $4.7 million for the fourth quarter of 2010.

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        Since our cash flows consist almost exclusively of distributions from the Partnership, we also ceased making dividends to our stockholders during 2009. With the resumption of distributions from the Partnership in 2010, we also resumed quarterly dividend payments to our common stockholders and paid quarterly dividends of $0.07 and $0.08 per share in November 2010 and February 2011, respectively.

        Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership's financial results and the results of our other subsidiaries. The interest owned by non-controlling partners' share of income is reflected separately in our results of operations. We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Our consolidated results of operations are derived from the results of operations of the Partnership and also include our gains on the issuance of units in the Partnership, deferred taxes, interest of non-controlling partners in the Partnership's net income, interest income (expense) and general and administrative expenses not reflected in the Partnership's results of operation. Accordingly, the discussion of our financial position and results of operations in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" primarily reflects the operating activities and results of operations of the Partnership.

        The Partnership's primary focus is on the gathering, processing, transmission and marketing of NGLs which it manages in regional reporting segments of midstream activity. The Partnership's geographic focus is in the North Texas Barnett Shale (NTX) and in Louisiana which has two reportable business segments (the LIG system and the south Louisiana processing and NGL assets, or PNGL). The Partnership manages its operations by focusing on gross operating margin because its 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.

        The Partnership's gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, and the volumes of NGLs handled at its fractionation facilities. The Partnership generates revenues from four primary sources:

•

purchasing and reselling or transporting natural gas on the pipeline systems it owns;



•

processing natural gas at its processing plants;



•

fractionating and marketing the recovered NGLs; and



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providing compression services.

        The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys 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 transports and resells the natural gas at the market index. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership's gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership 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 the Partnership's purchase/sale transactions, the resale price is generally

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based on the same index at which the gas was purchased. However, on occasion the Partnership has 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 it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as margin. Changes in the basis spread can increase or decrease the margins.

        One contract (the "Delivery Contract") has a term to 2019 that obligates the Partnership to supply approximately 150,000 MMBtu/d of gas. At the time that the Partnership entered into the Delivery Contract in 2008, it had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract. The Partnership's agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of its sales price for such gas less certain fees and costs. Accordingly, the Partnership was 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 the 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, the Partnership has had to purchase a portion of the gas to fulfill its obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

        The Partnership has recorded a loss of approximately $8.4 million during the year ended December 31, 2010 on the Delivery Contract. The Partnership expects that it 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.

        The Partnership also realizes gross operating margins from its processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements the Partnership's 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 the Partnership's 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, ad valorem taxes, repair and maintenance expenses, measurement 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.

Business Strategy

        The Partnership's business strategy will focus on increasing its distributable cash flow. Key elements of the Partnership strategy will include the following:

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Undertake selective construction and expansion opportunities on the Partnership's existing systems. The Partnership intends to leverage its existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for the Partnership's gathering, transmission, processing and marketing services.

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



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Pursue accretive acquisitions or construction of facilities in new areas.  The Partnership 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.  The Partnership continues to operate its existing asset base to maximize cost efficiencies, provide flexibility for its customers and provide reliable capacity for its customers. The Partnership will continue to focus on safety, environmental integrity, innovation and customer service.

Asset Dispositions

        During the past two years, the Partnership has repositioned its business through asset dispositions, debt restructuring and improving existing system profitability. These transactions and its improved profitability allowed the Partnership to resume distributions to its common unit holders in the third quarter of 2010. The Partnership believes the resumption of its distribution is an important milestone in accessing the capital markets to support its future growth strategies. Based on the Partnership's resumption of distributions, we also resumed our dividends in the third quarter of 2010.

        Historically, the Partnership has 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, the Partnership sold its Alabama, Mississippi and south Texas Midstream properties; and in October 2009 the Partnership sold its Treating assets.

Impact of Federal Income Taxes

        Crosstex Energy, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law. We expect to have taxable income allocated to us as a result of our investment in the Partnership's units, particularly because of remedial allocations that will be made among the unitholders. Taxable income allocated to us by the Partnership will increase over the years as the results of operation increase and as the ratio of income to distributions increases for all of the unitholders.

        As of December 31, 2010 we have a net operating loss carry forward of $90.4 million for federal income taxes and state loss carry forwards of $56.6 million. We believe it is more likely than not that our future results of operations will generate sufficient taxable income to utilize these net operating loss carry forwards before they expire. Once these net operating loss carry forwards are fully utilized, we will have to pay tax on our federal taxable income at a maximum rate of 35.0% under current law.

        Our use of this net operating loss carry forward will be limited if there is a greater than 50.0% change in our stock ownership over a three year period.

Commodity Price Risk

        The Partnership's business is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. For the year ended December 31, 2010 approximately 10.6% of the Partnership's processed gas arrangements, based on volume, was processed under percent of liquids (POL) contracts. A significant volume of inlet gas at

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the Partnership's south Louisiana and north Texas processing plants is settled under POL agreements. Under these contracts the Partnership receives 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, the Partnership's revenues under these contracts are directly impacted by the market price of NGLs.

        The Partnership also realizes processing gross margins under processing margin (margin) contracts. For the year ended December 31, 2010 approximately 12.9% of the Partnership's processed gas arrangements, based on volume, was processed under margin contracts. The Partnership has a number of margin contracts on the Plaquemine and Gibson processing plants. Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes 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 used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. The Partnership's margins from these contracts can be negative during periods of high natural gas prices relative to liquids prices.

        The Partnership is 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 the assets and on its margins for transportation between certain market centers. Low prices for these products will reduce the demand for the Partnership's services and volumes on its systems.

        In the past, the prices of natural gas and NGLs have been extremely volatile and the Partnership expects 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 the profitability by influencing drilling activity and well operations, and thus the volume of gas the Partnership gathers and processes. The volatility in commodity prices may cause the Partnership's gross operating margin and cash flows to vary widely from period to period. Partnership hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the Partnership's throughput volumes. For a discussion of the Partnership's 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. The Partnership manages its operations by focusing on gross operating margin which the Partnership defines as operating revenue minus cost of purchased gas and NGLs as reflected in the table below.