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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

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

FORM 10-K

(Mark One)    
ý   ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                to                               

Commission file number: 000-50536

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

Delaware
(State of organization)
  52-2235832
(I.R.S. Employer Identification No.)

2501 CEDAR SPRINGS
DALLAS, TEXAS

(Address of principal executive offices)

 

75201
(Zip Code)

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

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

Title of Each Class   Name of each exchange on which registered
Common Stock, Par Value $0.01 Per Share   The NASDAQ Global Select Market

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):

Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

         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.


Table of Contents


TABLE OF CONTENTS

DESCRIPTION

Item
   
  Page  
PART I  

1.

 

BUSINESS

 

 

3

 

1A.

 

RISK FACTORS

 

 

21

 

1B.

 

UNRESOLVED STAFF COMMENTS

 

 

38

 

2.

 

PROPERTIES

 

 

38

 

3.

 

LEGAL PROCEEDINGS

 

 

38

 

4.

 

RESERVED

 

 

39

 

PART II

 

5.

 

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

 

40

 

6.

 

SELECTED FINANCIAL DATA

 

 

42

 

7.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

 

46

 

7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

 

72

 

8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

 

75

 

9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

 

75

 

9A.

 

CONTROLS AND PROCEDURES

 

 

75

 

9B.

 

OTHER INFORMATION

 

 

75

 

PART III

 

10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

 

76

 

11.

 

EXECUTIVE COMPENSATION

 

 

77

 

12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

 

 

77

 

13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 

 

78

 

14.

 

PRINCIPAL ACCOUNTING FEES AND SERVICES

 

 

78

 

PART IV

 

15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

 

79

 

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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:

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

    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:

    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

    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:

    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;

    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

    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.

GRAPHIC

        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:

    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.

    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.

    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:

    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.

    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.

    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.

    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.

    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.

    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:

    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.

      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.

      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%.

        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.

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

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

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

    Blue Water Gas Processing Plant.  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.

GRAPHIC

        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 24th 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.

 
  Common Stock Price Range   Cash Dividends  
 
  Declared Per Share  
 
  High   Low  

2010:

                   
 

Quarter Ended December 31

  $ 9.78   $ 7.82   $ 0.08  
 

Quarter Ended September 30

    8.45     5.65     0.07  
 

Quarter Ended June 30

    9.65     6.02      
 

Quarter Ended March 31

    9.68     6.37      

2009:

                   
 

Quarter Ended December 31

  $ 6.57   $ 4.13      
 

Quarter Ended September 30

    5.60     3.13      
 

Quarter Ended June 30

    5.40     1.79      
 

Quarter Ended March 31

    6.71     0.79      

        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).

GRAPHIC

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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."

 
  Crosstex Energy, Inc.  
 
  Years Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (In thousands, except per share data)
 

Statement of Operations Data:

                               
 

Revenues:

                               
   

Midstream

  $ 1,792,676   $ 1,583,551   $ 3,558,213   $ 2,635,329   $ 1,835,048  
 

Operating costs and expenses:

                               
   

Purchased gas and NGLs

    1,454,376     1,272,329     3,250,427     2,375,503     1,676,692  
   

Operating expenses

    105,060     110,394     125,762     91,236     65,916  
   

General and administrative

    51,172     62,491     72,377     62,270     45,724  
   

(Gain) loss on derivatives

    9,100     (2,994 )   (8,619 )   (4,147 )   (174 )
   

Gain on sale of property

    (13,881 )   (666 )   (947 )   (1,024 )   (1,936 )
   

Impairments

    1,311     2,894     30,177          
   

Depreciation and amortization

    111,625     119,162     107,652     83,361     56,410  
                       
     

Total operating costs and expenses

    1,718,763     1,563,610     3,576,829     2,607,199     1,842,632  
                       
     

Operating income (loss)

    73,913     19,941     (18,616 )   28,130     (7,584 )
 

Other income (expense):

                               
   

Interest expense, net

    (87,028 )   (95,078 )   (74,861 )   (47,649 )   (19,512 )
   

Loss on extinguishment of debt

    (14,713 )   (4,669 )            
   

Other income

    294     1,449     27,898     538     1,802  
                       
     

Total other income (expense)

    (101,447 )   (98,298 )   (46,963 )   (47,111 )   (17,710 )
                       
 

Loss from continuing operations before income taxes and gain on issuance of Partnership units

    (27,534 )   (78,357 )   (65,579 )   (18,981 )   (25,294 )
 

Income tax benefit (provision)

    6,021     6,020     1,375     (6,319 )   (7,833 )
 

Gain on issuance of Partnership units(1)

            14,748     7,461     18,955  
                       
 

Loss from continuing operations before cumulative effect of change in accounting principle, net of tax

    (21,513 )   (72,337 )   (49,456 )   (17,839 )   (14,172 )
 

Discontinued Operations:

                               
 

Income (loss) from discontinued operations, net of tax

        (1,519 )   21,466     26,817     17,429  
 

Gain from sale of discontinued operations, net of tax

        159,961     42,753          
                       
 

Discontinued operations, net of tax

        158,442     64,219     26,817     17,429  
                       
 

Net income (loss) before cumulative effect of change in accounting principle

    (21,513 )   86,105     14,763     8,978     3,257  
 

Cumulative effect of change in accounting principle

                    170  
                       
 

Net income (loss)

    (21,513 )   86,105     14,763     8,978     3,427  

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  Crosstex Energy, Inc.  
 
  Years Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (In thousands, except per share data)
 
 

Less: Interest of non-controlling partners in the Partnership's net income (loss):

                               
   

Interest of non-controlling partners in the Partnership's continuing operations

    (9,862 )   (48,069 )   (55,704 )   (22,331 )   (24,881 )
   

Interest of non-controlling partners in the Partnership's discontinued operations

        (1,137 )   15,454     19,133     11,853  
   

Interest of non-controlling partners in the Partnership's gain on sale of discountinued operations

        119,669     30,780          
                       
   

Total interest of non-controlling partner in the partnership's net income (loss)

    (9,862 ) $ 70,463     (9,470 )   (3,198 )   (13,028 )
                       
 

Net income (loss) attributable to Crosstex Energy, Inc. 

  $ (11,651 ) $ 15,642   $ 24,233   $ 12,176   $ 16,455  
                       
 

Net income (loss) per common share—basic

  $ (0.24 ) $ 0.33   $ 0.52   $ 0.26   $ 0.39  
 

Net income (loss) per common share—diluted

  $ (0.24 ) $ 0.33   $ 0.51   $ 0.26   $ 0.39  
 

Dividends per share—common(2)

  $ 0.07   $ 0.09   $ 1.32   $ 0.91   $ 0.807  

Balance Sheet Data (end of period):

                               
 

Working capital deficit

  $ (12,781 ) $ (41,791 ) $ (20,431 ) $ (39,330 ) $ (70,091 )
 

Property and equipment, net

    1,216,166     1,280,197     1,528,490     1,426,546     1,107,242  
 

Total assets

    1,991,103     2,080,233     2,546,743     2,602,829     2,206,698  
 

Long-term and current maturities of debt

    718,570     873,702     1,263,706     1,223,118     987,130  
 

Capital lease obligations (including current maturities)

    31,327     23,799     27,896     3,988      
 

Interest of non-controlling partners in the Partnership

    717,063     587,624     522,961     489,034     391,103  
 

Stockholders' equity

    901,478     815,910     738,390     246,366     279,413  

Cash Flow Data:

                               
 

Net cash flow provided by (used in)(3):

                               
   

Operating activities

  $ 84,790   $ 78,850   $ 170,154   $ 112,578   $ 113,839  
   

Investing activities

    14,638     379,874     (186,768 )   (411,382 )   (885,825 )
   

Financing activities

    (87,351 )   (461,980 )   22,720     296,022     769,717  

Non-GAAP Financial Measures:

                               
 

Gross operating margin(4)

  $ 338,300   $ 311,222   $ 307,786   $ 259,826   $ 158,356  
 

Partnership's adjusted EBITDA(5)

  $ 186,880   $ 158,682   $ 163,394   $ 126,944   $ 58,773  

Operating Data:

                               
 

Pipeline throughput (MMBtu/d)

    1,971,000     2,040,000     2,002,000     1,555,000     845,000  
 

Natural gas processed (MMBtu/d)

    1,366,000     1,235,000     1,608,000     1,835,000     1,817,000  
 

Producer services (MMBtu/d)

    99,000     75,000     85,000     94,000     138,000  
 

NGL Fractionation (Gals/d)

    922,000     686,000     956,000     980,000     1,497,000  

(1)
We recognized gains of $14.7 million in 2008, $7.5 million in 2007 and $19.0 million in 2006 as a result of the Partnership issuing additional units in public offerings at prices per unit greater than our equivalent carrying value.

(2)
Dividend Paid.

(3)
Cash flow data includes cash flows from discontinued operations.

(4)
Gross operating margin is defined as revenue less related cost of purchased gas and NGLs.

(5)
Partnership's adjusted EBITDA is defined 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.

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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):

 
  Years Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (In thousands)
 

Net income (loss)

  $ (11,651 ) $ 15,642   $ 24,233   $ 12,176   $ 16,455  

Interest expense

    87,028     95,078     74,861     47,649     19,512  

Depreciation and amortization

    111,625     119,162     107,652     83,361     56,410  

Impairment

    1,311     2,894     30,177          

Loss on extinguishment of debt

    14,713     4,669              

Gain on sale of property

    (13,881 )   (666 )   (947 )   (1,024 )   (1,936 )

Stock-based compensation

    9,569     8,854     11,279     12,259     8,578  

(Income) loss from discontinued opertations, net of tax

        1,519     (21,466 )   (26,817 )   (17,429 )

Gain on sale of discontinued operations, net of tax

        (159,961 )   (42,753 )        

Gain on issuance of Partnership units

            (14,748 )   (7,461 )   (18,955 )

Minority interest

    (9,862 )   70,463     (9,470 )   (3,198 )   (13,028 )

Taxes

    (6,021 )   (6,020 )   (1,375 )   6,319     7,833  

Other (a)

    4,049     7,048     5,951     3,680     1,333  
                       

Partnership's adjusted EBITDA

  $ 186,880   $ 158,682   $ 163,394   $ 126,944   $ 58,773  
                       

(a)
Includes the Partnership's financial derivatives marked-to-market, the Partnership's severance and exit expenses (as allowed for adjustment under the Partnership's credit facility) and CEI's direct general and administrative expenses and other income are not included in the Partnership's adjusted EBTIDA.

        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):

 
  Years Ended December 31,  
 
  2010   2009   2008   2007   2006  

Total gross operating margin

  $ 338,300   $ 311,222   $ 307,786   $ 259,826   $ 158,356  

Add (deduct):

                               

Operating expenses

    (105,060 )   (110,394 )   (125,762 )   (91,236 )   (65,916 )

General and administrative expenses

    (51,172 )   (62,491 )   (72,377 )   (62,270 )   (45,724 )

Gain on sale of property

    13,881     666     947     1,024     1,936  

Gain (loss) on derivatives

    (9,100 )   2,994     8,619     4,147     174  

Depreciation, amortization and impairments

    (112,936 )   (122,056 )   (137,829 )   (83,361 )   (56,410 )
                       

Operating income

  $ 73,913   $ 19,941   $ (18,616 ) $ 28,130   $ (7,584 )
                       

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

    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:

    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.

    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.

 
  Years ended December 31,  
 
  2010   2009   2008  
 
  (Dollars in millions)
 

LIG Segment

                   

Revenues

  $ 963.0   $ 893.8   $ 2,198.0  

Purchased gas and NGLs

    (845.6 )   (793.0 )   (2,097.3 )
               

Total gross operating margin

  $ 117.4   $ 100.8   $ 100.7  
               

NTX Segment

                   

Revenues

  $ 399.5   $ 509.4   $ 976.7  

Purchased gas and NGLs

    (240.1 )   (352.8 )   (830.7 )
               

Total gross operating margin

  $ 159.4   $ 156.6   $ 146.0  
               

PNGL Segment

                   

Revenues

  $ 602.6   $ 297.9   $ 561.5  

Purchased gas and NGLs

    (541.1 )   (250.1 )   (512.0 )
               

Total gross operating margin

  $ 61.5   $ 47.8   $ 49.5  
               

Corporate

                   

Revenues

  $ (172.4 ) $ (117.6 ) $ (178.0 )

Purchased gas and NGLs

    172.4     123.6     189.6  
               

Total gross operating margin

  $   $ 6.0   $ 11.6  
               

Total

                   

Revenues

  $ 1,792.7   $ 1,583.5   $ 3,558.2  

Purchased gas and NGLs

    (1,454.4 )   (1,272.3 )   (3,250.4 )
               

Total gross operating margin

  $ 338.3   $ 311.2   $ 307.8  
               

Midstream Volumes:

                   

LIG

                   

Gathering and Transportation (MMBtu/d)

    902,000     900,000     960,000  

Processing (MMBtu/d)

    283,000     269,000     310,000  

NTX

                   

Gathering and Transportation (MMBtu/d)

    1,069,000     1,111,000     1,000,000  

Processing (MMBtu/d)

    209,000     219,000     200,000  

PNGL

                   

Processing (MMBtu/d)

    874,000     747,000     1,098,000  

NGL Fractionation (Gals/d)

    922,000     686,000     956,000  

Commercial Services (MMBtu/d)

    99,000     75,000     85,000  

Corporate

                   

Gathering and Transportation (MMBtu/d)

        29,000     42,000  

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

        Gross Operating Margin.    Gross operating margin was $338.3 million for the year ended December 31, 2010 compared to $311.2 million for the year ended December 31, 2009, an increase of $27.1 million, or 8.7%. The increase was due to higher margins on the Partnership's gathering and transmission throughput volume, as well as a favorable NGL market throughout the year. The following provides additional details regarding this change in gross operating margins:

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

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

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

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

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

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

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

    The Partnership was successful in renegotiating its existing compressor leases that resulted in $1.3 million of cost savings;

    The Partnership has expanded its Louisiana operations which caused operating expenses to increase by approximately $4.9 million;

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

    The Partnership's repairs and maintenance costs increased operating expenses by $3.3 million in 2010 over 2009.

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        General and Administrative Expenses.    General and administrative expenses were $51.2 million for the year ended December 31, 2010 compared to $62.5 million for the year ended December 31, 2009, a decrease of $11.3 million, or 18.1%. The decrease is primarily a result of the following:

    The Partnership reduced its workforce in 2009 which resulted in a decrease of $9.4 million in labor and benefits; and

    The Partnership lowered its legal and professional costs by $2.4 million in 2010.

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

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

 
  Years Ended December 31,  
 
  2010   2009  
(Gain) Loss on Derivatives:
  Total   Realized   Total   Realized  

Basis swaps

  $ 5.6   $ 2.3   $ (4.4 ) $ (2.5 )

Processing margin hedges

    3.5     5.5     1.4     (2.2 )

Other

        0.1     (0.3 )   (1.4 )
                   

    9.1     7.9     (3.3 )   (6.1 )

Derivative losses included in income from discontinued operations

            0.3     0.5  
                   

Net (gain) loss from continuing operations

  $ 9.1   $ 7.9   $ (3.0 ) $ (5.6 )
                   

        Impairments.    During the year ended December 31, 2010, the Partnership had an impairment expense of $1.3 million compared to $2.9 million for the year ended December 31, 2009. During 2009, impairments totaling $2.9 million were taken on the Bear Creek processing plant and the Vermillion treating plant to bring the fair value of the plants to a marketable value for these idle assets, which were subsequently sold. During 2010, impairments totaling $1.3 million were taken on excess pipe that was ultimately sold later during 2010.

        Depreciation and Amortization.    Depreciation and amortization expenses were $111.6 million for the year ended December 31, 2010 compared to $119.2 million for the year ended December 31, 2009, a decrease of $7.5 million, or 6.3%. The decrease of $7.5 million was the result of an increase in estimated depreciable lives for certain of our processing plants based on 2009 depreciation study that resulted in a depreciation expense decrease of $9.1 million partially offset by $1.6 million increase in depreciation on the Eunice natural gas processing plants and fractionation facility purchased during fourth quarter 2009.

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        Interest Expense.    Interest expense was $87.0 million for the year ended December 31, 2010 compared to $95.1 million for the year ended December 31, 2009, a decrease of $8.1 million, or 8.5%. Net interest expense consists of the following (in millions):

 
  Years Ended December 31,  
 
  2010   2009  

Senior notes (secured and unsecured)

  $ 62.5   $ 28.8  

Paid-in-kind interest on senior secured notes

    1.4     4.9  

Bank credit facility

    10.0     35.4  

Series B secured notes

    1.1     0.4  

Capitalized interest

    (0.1 )   (1.1 )

Mark to market interest rate swaps

    (22.4 )   (0.8 )

Interest income

        (0.2 )

Realized interest rate swap losses

    26.5     19.0  

Amortization of debt issue costs

    6.6     7.6  

Other

    1.4     1.1  
           
 

Total

  $ 87.0   $ 95.1  
           

        Loss on Extinguishment of Debt.    The Partnership recognized a loss on extinguishment of debt during the years ended December 31, 2010 and 2009 of $14.7 million and $4.7 million, respectively. In February 2010, the Partnership repaid its prior credit facility and senior secured notes which resulted in make-whole interest payments on its senior secured notes and the write-off of unamortized debt costs totaling $14.7 million. The loss of $4.7 million on extinguishment of debt incurred in the year ended December 31, 2009 related to the amendment of its prior credit facility and the senior secured notes in February 2009.

        Income Taxes.    We provide for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. An income tax benefit of $6.0 million was recorded on the loss from operations (net of non-controlling interest) for the year ended December 31, 2010. A net income tax benefit of $6.0 million was also recorded for the year ended December 31, 2009 comprised of an income tax benefit of $10.6 million recorded on the loss from continuing operations (net of non-controlling interest) partially offset by a tax expense of $4.6 million attributable to the conversion of the Partnership's senior subordinated series D units to common units in 2009.

        Discontinued Operations.    During 2009, the Partnership sold the following non-strategic assets and used the proceeds from such sales to repay long-term indebtedness:

Assets
  Date of Sale

Oklahoma assets (Arkoma system)

  February 2009

Alabama, Mississippi and south Texas assets

  August 2009

Treating assets

  October 2009

        In accordance with FASB ASC 360-10-05-4, the results of operations related to each of the assets listed above (except the Oklahoma assets, which were immaterial to the financial statement presentations) are presented in income from discontinued operations for the comparative periods in the statements of operations. Revenues, operating expenses, general and administrative expenses associated directly to the assets sold, depreciation and amortization, allocated Texas margin tax and allocated interest are reflected in the income from discontinued operations. No corporate office general and administrative expenses have been allocated to income from discontinued operations. Following are the

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components of revenues and earnings from discontinued operations and operating data (dollars in millions):

 
  Year ended
December 31, 2009
 

Midstream revenues

  $ 327.2  

Treating revenues

  $ 45.5  

Income from discontinued operations, net of tax

  $ (1.5 )

Gain from sale of discontinued operations, net of tax

  $ 160.0  

Gathering and Transmission Volumes (MMBtu/d)

    564,000  

Processing Volumes (MMBtu/d)

    191,000  

        Interest of Non-Controlling Partners in the Partnership's Net Income (Loss) from Continuing Operations.    The interest of non-controlling partners in the Partnership's net loss was $9.9 million for the year ended December 31, 2010 compared to a net loss of $48.1 million for the year ended December 31, 2009 due to the changes shown in the following summary (in millions):

 
  Years ended December 31,  
 
  2010   2009  

Net loss from continuing operations for the Partnership

  $ (25.8 ) $ (77.5 )

(Income) allocation to CEI for the general partner incentive distribution

    (0.1 )    

Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors

    3.9     3.0  

Loss allocation to CEI for its 2% general partner share of Partnership loss

    0.6     1.5  
           

Net loss allocable to limited partners

    (21.4 )   (73.0 )

Less: CEI's share of net (income) loss allocable to limited partners

    11.5     24.9  
           

Non-controlling partners' share of Partnership net loss from continuing operations

  $ (9.9 ) $ (48.1 )
           

    Year ended December 31, 2009 Compared to Year ended December 31, 2008

        Gross Operating Margin.    Gross operating margin was $311.2 million for the year ended December 31, 2009 compared to $307.8 million for the year ended December 31, 2008, an increase of $3.4 million, or 1.1%. The increase was primarily due to higher margins on the Partnership's gathering and transmission throughput volume. These increases were partially offset by gross operating margin declines in the processing business due to a less favorable NGL market. The following provides additional details regarding this change in gross operating margin:

    The LIG segment contributed gross operating margin growth of $0.1 million for the year ended December 31, 2009 over the same period in 2008. The gathering and transmission assets generated approximately $17.1 million of gross operating margin growth primarily due to improved pricing and higher volumes on the northern part of the system offsetting a decrease in sales volume at southern delivery points. The weaker processing environment contributed to a significant decline in the gross margins for the LIG processing plants for the period. The primary contributors to this decrease were the Gibson and Plaquemine plants which had gross operating margin declines of $9.8 million and $7.6 million, respectively, for the year ended December 31, 2009.

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    The NTX segment contributed $10.6 million of gross operating margin growth for the year ended December 31, 2009 over the same period in 2008 due to increased volume on the gathering systems.

    The weaker processing environment contributed to a $1.7 million decline in gross operating margin for the PNGL segment for the comparative periods. Overall the plants in the region reported a margin decrease of approximately $9.1 million. The primary contributor to this decrease was the Blue Water processing plant which had a gross operating margin decline of $3.5 million for the period. These declines were offset by increases in the fractionation and liquids marketing activities in the region.

    The corporate segment reported a gross operating margin decrease of approximately $5.7 million for the year ended December 31, 2009 over the same period in 2008. The Arkoma system, which was sold in April 2009, created a negative gross margin variance of $4.0 million when compared to the same period in 2008. The Crosstex Pipeline system in east Texas had a gross operating margin decline of $1.7 million primarily due to a decline in throughput volumes.

        Operating Expenses.    Operating expenses were $110.4 million for the year ended December 31, 2009 compared to $125.8 million for the year ended December 31, 2008, a decrease of $15.4 million, or 12.2%, resulting primarily from initiatives undertaken in late 2008 and early 2009 to reduce expenses. The key initiatives undertaken to reduce operating costs included:

    The Partnership ran only one of the Eunice processing trains during 2009 as compared to running two trains in 2008 thereby reducing the overall operating expenses for the plant;

    The Partnership reduced the use of contract labor in its field operations by reallocating available capacity of in-house personnel due to the slow down in its field expansion projects;

    The Partnership reduced rental cost by renegotiating compressor rental rates, consolidated compressor operations for facilities that were not fully utilized and buying out the Eunice plant operating lease in October 2009; and

    The Partnership renegotiated rates for various materials and supplies, primarily chemical costs, to reduce such costs.

        These cost initiatives resulted in a reduction of contractor services and related costs of $6.7 million, chemical and material costs of $3.2 million and rental costs of $3.1 million. The Partnership also reduced its operating costs by $2.1 million between 2009 and 2008 as a result of the April 2009 sale of Arkoma system.

        General and Administrative Expenses.    General and administrative expenses were $62.5 million for the year ended December 31, 2009 compared to $72.4 million for the year ended December 31, 2008, a decrease of $9.9 million, or 13.7%. The decrease is primarily a result of the following:

    The Partnership reduced its general and administrative staff in 2009 and realized a cost savings from this workforce reduction;

    The Partnership's workforce reduction also resulted in the non-recurring increase of cost in 2009 for severance payments and the termination of office space; and

    The Partnership also recognized increased bad debt expense related to the bankruptcy of SemStream, L.P.

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        Gain/Loss on Derivatives.    The Partnership had a gain on derivatives of $3.0 million for the year ended December 31, 2009 compared to a gain of $8.6 million for the year ended December 31, 2008. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):

 
  Years Ended December 31,  
 
  2009   2008  
(Gain) Loss on Derivatives:
  Total   Realized   Total   Realized  

Basis swaps

  $ (4.4 ) $ (2.5 ) $ (8.7 ) $ (8.8 )

Processing margin hedges

    1.4     (2.2 )   (3.6 )   (3.6 )

Other

    (0.3 )   (1.4 )   (1.4 )   (0.9 )
                   

  $ (3.3 ) $ (6.1 ) $ (13.7 ) $ (13.3 )

Derivative losses included in income from discontinued operations

    0.3     0.5     5.1     5.4  
                   

Net gain from continuing operations

  $ (3.0 ) $ (5.6 ) $ (8.6 ) $ (7.9 )
                   

        Impairments.    Impairment expense was $2.9 million for the year ended December 31, 2009 compared to $30.2 million during the year ended December 31, 2008. During 2009, impairments totaling $2.9 million were taken on the Bear Creek processing plant and the Vermillion treating plant to bring the fair value of the plants to a marketable value for these idle assets, which were subsequently sold. The impairment expense during 2008 is comprised of:

    $17.8 million related to the Blue Water gas processing plant located in south Louisiana—The impairment on the Partnership's 59.27% interest in the Blue Water gas processing plant was recognized because the pipeline company which owns the offshore Blue Water system and supplies gas to our Blue Water plant reversed the flow of the gas on its pipeline in early January 2009 thereby removing access to all the gas processed at the Blue Water plant from the Blue Water offshore system. As of January 2009, an alternative source of new gas for the Blue Water plant had not been found so the plant ceased operation from January 2009 until November 2009. An impairment of $17.8 million was recognized for the carrying amount of the plant in excess of the estimated fair value of the plant as of December 31, 2008.

    $5.7 million related to goodwill—It was determined that the carrying amount of goodwill attributable to the Midstream segment was impaired because of the significant decline in Midstream operations due to negative impacts on cash flows caused by the significant declines in natural gas and NGL prices during the last half of 2008 coupled with the global economic decline.

    $4.1 million related to leasehold improvements—The Partnership had planned to relocate its corporate headquarters during 2008 to a larger office facility. The Partnership had leased office space and was close to completing the renovation of this office space when the global economic decline began impacting operations in October 2008. On December 31, 2008, the decision was made to cancel the new office lease and not relocate the corporate offices from its existing office location. The impairment relates to the leasehold improvements on the office space for the cancelled lease.

    $2.6 million related to the Arkoma gathering system—The impairment on the Arkoma gathering system was recognized because the asset was sold in February 2009 for $10.7 million and the carrying amount of the plant exceeded the sale price by approximately $2.6 million.

        Depreciation and Amortization.    Depreciation and amortization expenses were $119.2 million for year ended December 31, 2009 compared to $107.7 million for the year ended December 31, 2008, an increase of $11.5 million, or 10.7%, resulting primarily from growth and expansion in the NTP, NTG

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and north Louisiana areas that was completed and put in-service during the later part of 2008 and early 2009.

        Interest Expense.    Interest expense was $95.1 million for the year ended December 31, 2009 compared to $74.9 million for the year ended December 31, 2008, an increase of $20.2 million, or 27.0%. Net interest expense consists of the following (in millions):

 
  Years Ended December 31,  
 
  2009   2008  

Senior notes (secured)

  $ 28.8   $ 24.3  

Paid-in-kind interest on senior secured notes

    4.9      

Bank credit facility

    35.4     23.3  

Series B secured notes

    0.4      

Capitalized interest

    (1.1 )   (2.6 )

Mark to market interest rate swaps

    (0.8 )   22.1  

Realized interest rate swap losses

    19.0     4.6  

Interest income

    (0.2 )   (0.3 )

Amortization of debt issue costs

    7.6     2.8  

Other

    1.1     0.7  
           
 

Total

  $ 95.1   $ 74.9  
           

        Loss on Extinguishment of Debt.    The Partnership recognized a loss on extinguishment of debt during the year ended December 31, 2009 of $4.7 million due to the February 2009 amendment to the senior secured notes agreement. The modifications to this agreement pursuant to this amendment were substantive as defined in FASB ASC 470-50 and were accounted for as the extinguishment of the old debt and the creation of new debt. As a result, the unamortized costs associated with the senior secured notes prior to the amendment as well as the fees paid to the senior secured lenders for the February 2009 amendment were expensed during the year ended December 31, 2009.

        Other Income.    Other income was $1.4 million for the year ended December 31, 2009 compared to $27.9 million for the year ended December 31, 2008. In November 2008, the Partnership sold a contract right for firm transportation capacity on a third party pipeline to an unaffiliated third party for $20.0 million. The entire amount of such proceeds was reflected in other income because the Partnership had no basis in this contract right. In February 2008, the Partnership recorded $7.0 million from the settlement of disputed liabilities that were assumed with an acquisition.

        Income Taxes.    We provide for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. A net income tax benefit of $6.0 million was recorded for the year ended December 31, 2009 comprised of an income tax benefit of $10.6 million recorded on the loss from continuing operations (net of non-controlling interest) partially offset by a tax expense of $4.6 million attributable to the conversion of the Partnership's senior subordinated series D units to common units in 2009. A net income tax benefit of $1.4 million was recorded for the year ended December 31, 2008 primarily due to an income tax expense of $2.5 million on income from continuing operations (net of non-controlling interest) and an income tax expense for the Texas Margin tax of $1.2 million, offset by an income tax benefit of $5.2 million attributable to the conversion of the Partnership's senior subordinated series C units to common units in 2008.

        Gain on the Issuance of Units of the Partnership.    As a result of the Partnership issuing common units in April 2008 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and we recognized a gain on issuance of such units.

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        Discontinued Operations.    During 2008 and 2009, the Partnership sold non-strategic assets and used the proceeds from such sales to repay long-term indebtedness.

Assets
  Date of Sale

12.4% interest in the Seminole Gas Processing Plant

  November 2008

Oklahoma assets (Arkoma system)

  February 2009

Alabama, Mississippi and south Texas assets

  August 2009

Treating assets

  October 2009

        In accordance with FASB ASC 360-10-05-4, the results of operations related to these assets (except the Oklahoma assets, which were immaterial to the financial statement presentations) are presented in income from discontinued operations for the comparative periods in the statements of operations. Revenues, operating expenses, general and administrative expenses associated directly to the assets sold, depreciation and amortization, allocated Texas margin tax and allocated interest are reflected in the income from discontinued operations. Following are the components of revenues and earnings from discontinued operations and operating data (dollars in millions):

 
  Years Ended December 31,  
 
  2009   2008  

Midstream revenues

  $ 327.2   $ 1,349.7  

Treating revenues

  $ 45.5   $ 73.5  

Income from discontinued operations, net of tax

  $ (1.5 ) $ 21.5  

Gain from sale of discontinued operations, net of tax

  $ 160.0   $ 42.8  

Gathering and Transmission Volumes (MMBtu/d)

    564,000     617,000  

Processing Volumes (MMBtu/d)

    191,000     204,000  

        Interest of Non-Controlling Partners in the Partnership's Net Income (Loss) from Continuing Operations.    The interest of non-controlling partners in the Partnership's net loss was $48.1 million for the year ended December 31, 2010 compared to a net loss of $55.7 million for the year ended December 31, 2009 due to the changes shown in the following summary (in millions):

 
  Years ended December 31,  
 
  2009   2008  

Net loss from continuing operations for the Partnership

  $ (77.5 ) $ (63.7 )

(Income) allocation to CEI for the general partner incentive distribution

        (30.8 )

Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors

    3.0     4.7  

Loss allocation to CEI for its 2% general partner share of Partnership loss

    1.5     1.2  
           

Net loss allocable to limited partners

    (73.0 )   (88.6 )

Less: CEI's share of net (income) loss allocable to limited partners

    24.9     32.6  

Plus: Non-controlling partners' share of net income in Denton County Joint Venture

        0.3  
           

Non-controlling partners' share of Partnership net loss from continuing operations

  $ (48.1 ) $ (55.7 )
           

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Critical Accounting Policies

        The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. See Note 2 of the Notes to Consolidated Financial Statements for further details on our accounting policies.

        Revenue Recognition and Commodity Risk Management.    The Partnership recognizes revenue for sales or services at the time the natural gas or NGLs are delivered or at the time the service is performed. It generally accrues one month of sales and the related gas purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

        The Partnership utilizes extensive estimation procedures to determine the sales and cost of gas purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. It uses actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month or two following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as "actualization". Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month's accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. The Partnership believes that its accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

        The Partnership engages in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and NGLs. It also manages its price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance its future commitments and significantly reduce its risk to the movement in natural gas prices.

        The Partnership uses derivatives to hedge against changes in cash flows related to product prices and interest rate risk, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

        The Partnership conducts "off-system" gas marketing operations as a service to producers on systems that it does not own. It refers to these activities as part of energy trading activities. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, the Partnership purchases the natural gas from the producer and

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enters into a sales contract with another party to sell the natural gas. The revenue and cost of sales for these activities are included in revenue on a net basis in the statement of operations.

        The Partnership manages its price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas prices. However, the Partnership is subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives, and it uses mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized in earnings as gain or loss on derivatives immediately.

        Sales of Securities by Subsidiaries.    Prior to 2009, we recognized gains and losses in the consolidated statements of operations resulting from subsidiary sales of additional equity interest, including the Partnership's limited partnership units to unrelated parties. Pursuant to new accounting guidance adopted effective January 1, 2009, we reflect changes in our ownership interest in the Partnership as equity transactions. The carrying amount of the non-controlling interest is adjusted to reflect the change in our ownership interest in the Partnership. Any difference between the fair value of the consideration received and the amount by which the non-controlling interest is adjusted is recognized in additional paid-in capital.

        Impairment of Long-Lived Assets.    In accordance with FASB ASC 360-10-05, the Partnership evaluates the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

        When determining whether impairment of one of the Partnership's long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. The estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

    changes in general economic conditions in regions in which our markets are located;

    the availability and prices of natural gas supply;

    the Partnership's ability to negotiate favorable sales agreements;

    the risks that natural gas exploration and production activities will not occur or be successful;

    our dependence on certain significant customers, producers, and transporters of natural gas; and

    competition from other midstream companies, including major energy producers.

        Any significant variance in any of the above assumptions or factors could materially affect the Partnership's cash flows, which could require us to record an impairment of an asset.

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        Depreciation Expense and Cost Capitalization.    Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipelines. The Partnership capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. The Partnership capitalizes the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

        The Partnership generally computes depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates may be reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

Liquidity and Capital Resources

        Cash flow presented in liquidity discussions includes cash flow from discontinued operations.

        Cash Flows from Operating Activities.    Net cash provided by operating activities was $84.8 million, $78.9 million and $170.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. Income before non-cash income and expenses and changes in working capital for 2010, 2009 and 2008 were as follows (in millions):

 
  Years ended December 31,  
 
  2010   2009   2008  

Income before non-cash income and expenses

  $ 58.8   $ 87.3   $ 157.6  

Changes in working capital

  $ 26.0   $ (8.4 ) $ 12.5  

        The primary reason for the decrease in cash flow from income before non-cash income and expenses of $28.5 million from 2009 to 2010 relates to payment for settlement of interest rate swaps, make-whole payments and PIK notes. The primary reason for the decreased cash flow from income before noncash income and expenses of $70.3 million from 2008 to 2009 was increased interest expense of $19.4 million, decreased operating income of $11.2 million, decreased other income of $26.8 million, and decreased gain on derivatives of $7.2 million.

        The change in working capital for 2010 primarily relates to accrued interest on the Partnership's long-term debt. As previously discussed, the Partnership pays interest semi-annually in February and August on the Partnership's new senior unsecured notes which caused the balance in accrued interest to increase by approximately $19.0 million as of December 31, 2010 as compared to December 31, 2009. The remaining change in working capital for 2010 and the changes in working capital for the 2009 and 2008 are due to normal fluctuations in trade receivables and payable balances due to timing of collections and payments.

        Cash Flows from Investing Activities.    Net cash was provided from investing activities of $14.6 million and $379.9 million for the years ended December 31, 2010 and 2009, respectively, primarily due to proceeds from asset sales. Net cash used in investing activity was $186.8 million for the year ended December 31, 2008. Cash flows from investing activities for the years ended December 31, 2010, 2009 and 2008 included proceeds from property sales of $60.2 million, $503.9 million and $88.8 million, respectively. The east Texas assets and a non-operational processing plant held in inventory were the primary assets sold in 2010 for $39.8 million and $19.5 million, respectively. In 2009, the Partnership sold its Arkoma system for approximately $10.7 million, the Partnership sold its

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midstream assets in Alabama, Mississippi and south Texas for approximately $217.6 million and the Partnership sold its natural gas treating business for $265.4 million. In 2008, the Partnership sold its 12.4% interest in the Seminole gas processing plant for $85.0 million. The Partnership's primary use of cash related to investing activities for the years ended December 31, 2010, 2009 and 2008 were capital expenditures and acquisitions, net of accrued amounts, as follows (in millions):

 
  Years Ended December 31,  
 
  2010   2009   2008  

Growth capital expenditures

  $ 37.4   $ 90.5   $ 257.3  

Acquisition and asset purchases

        35.1      

Maintenance capital expenditures

    10.8     10.9     18.3  
               
 

Total

  $ 48.2   $ 136.5   $ 275.6  
               

        Cash Flows from Financing Activities.    Net cash used in financing activities was $87.4 million and $462.0 million for the years ended December 31, 2010 and 2009, respectively, and financing activities provided net cash of $22.7 million for the year ended December 31, 2008. Financing activities during 2010 primarily relate to the issuance of senior unsecured notes, sale of preferred units and establishment of a new credit facility and repaying the old credit facility and senior secured notes. The Partnership's 2009 financing activities included disposal of non-core assets and repayment of outstanding debt. The Partnership's financings have primarily consisted of borrowings and repayments under bank credit facilities, borrowings and repayments under capital lease obligations, borrowings and repayments of senior secured and unsecured notes, debt refinancing costs and unit issuances during 2010, 2009 and 2008 as follows (in millions):

 
  Years ended December 31,  
 
  2010   2009   2008  

Net borrowings (repayments) under bank credit facilities(1)

  $ (529.6 ) $ (254.4 ) $ 50.0  

Senior secured note repayments(2)

    (316.5 )   (163.2 )   (9.4 )

Senior unsecured note borrowings (net of discount
on the note)

    711.5          

Series B secured note repayment

    (11.0 )        

Net borrowings (repayments) under capital lease obligations

    (2.4 )   (0.7 )   23.9  

Debt refinancing costs

    (28.6 )   (15.0 )   (4.9 )

Common unit offerings

            99.9  

Issuance of preferred units

    120.8          

                                    

                   

(1)
Year ended December 31, 2009 includes a $143.0 million and $173.3 million payment due to the sale of the Alabama, Mississippi and south Texas assets and the Treating assets, respectively.

(2)
Year ended December 31, 2009 includes a $69.0 million and $84.8 million payment due to sale of the Alabama, Mississippi and south Texas assets and the Treating assets, respectively.

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        Dividends to shareholders and distributions to non-controlling partners in the Partnership represent our primary use of cash in financing activities. Total cash distributions made during the last three years were as follows (in millions):

 
  Years ended December 31,  
 
  2010   2009   2008  

Dividends to shareholders

  $ 3.4   $ 4.2   $ 62.0  

Distributions to non-controlling partners

    19.0     7.6     63.2  
               
 

Total

  $ 22.4   $ 11.8   $ 125.2  
               

        In order to reduce our interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on the Partnership's revolving credit facility. The Partnership borrows money under our $420.0 million new credit facility to fund checks as they are presented. As of December 31, 2010, it had approximately $333.4 million of available borrowing capacity under this facility. Changes in drafts payable for 2010, 2009 and 2008 were as follows (in millions):

 
  Years ended December 31,  
 
  2010   2009   2008  

Decrease in drafts payable

  $ (5.1 ) $ (16.3 ) $ (7.4 )

        Working Capital Deficit.    We had a working capital deficit of $12.8 million as of December 31, 2010. Changes in working capital may fluctuate significantly between periods even though the Partnership's trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of its revenues are collected and a large volume of its gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although the Partnership strives to minimize natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period to period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includes mark to market derivative assets and liabilities associated with commodity derivatives which fluctuated significantly due to the changes in natural gas and NGL prices and associated with interest rate swap derivatives which fluctuated significantly due to changes in interest rates. The changes in working capital during the years ended December 31, 2010, 2009 and 2008 are due to the impact of the fluctuations discussed above.

        Off-Balance Sheet Arrangements.    We had no off-balance sheet arrangements as of December 31, 2010 and 2009.

        April 2008 Sale of Common Units.    On April 9, 2008, the Partnership issued 3,333,334 common units in a private offering at $30.00 per unit, which represented an approximate 7.0% discount from the market price on such date. Crosstex Energy GP, L.P. made a general partner contribution of $2.0 million in connection with the issuance to maintain its 2.0% general partner interest.

        January 2011 Sale of Preferred Units.    On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions for net proceeds of $120.8 million. Crosstex Energy, GP, L.P. made a general partner contribution of $2.6 million in connection with the issuance to maintain its 2% general partner interest. The 14,705,882 preferred units are convertible by the holders thereof at any time into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuance of common units. They are entitled to a quarterly distribution that is the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such

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quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units. The first and second quarterly preferred unit distributions of $3.1 million were paid in cash in May 2010 and August 2010. The third quarterly preferred unit distribution of $3.7 million was paid in November 2010 and the fourth quarter distribution of $3.8 million was paid in February 2011.

        Capital Projects for 2011.    The Partnership's 2011 capital budget includes approximately $42.7 million of identified growth projects, and it expects to fund such expenditures with internally generated cash flow. The Partnership's primary capital projects for 2011 include two expansion projects in north Texas and the restart of the Eunice fractionator in south Louisiana, all of which were underway as of December 31, 2010 with expected completions near the end of the first quarter of 2011. The construction of a new compressor station on an existing gathering line in north Texas at an estimated cost of $10.0 million is expected to generate annual cash flow of approximately $8.0 million. The second project in north Texas is a 15 mile expansion of our natural gas gathering system in the Barnett shale with an estimated cost of $25.0 million and is expected to generate average annual cash flows of $10.0 million per year for the first four years. The Eunice restart project is estimated to cost $9.0 million and generate annual cash flow of $3.0 million. The Partnership may identify more growth projects during 2011 in addition to projects currently budgeted.

        Total Contractual Cash Obligations.    A summary of the Partnership's total contractual cash obligations as of December 31, 2010, is as follows (in millions):

 
  Payments Due by Period  
 
  Total   2011   2012   2013   2014   2015   Thereafter  

Long-term debt obligations

  $ 732.1   $ 7.1   $   $   $   $   $ 725.0  

Interest payable on fixed long-term debt obligations

    481.9     64.7     64.3     64.3     64.3     64.3     160.0  

Capital lease obligations

    39.6     4.6     4.6     4.6     4.6     4.6     16.6  

Operating lease obligations

    43.7     13.5     9.6     6.6     5.0     3.7     5.3  

Purchase obligations

    2.4     2.4                      

Uncertain tax position obligations

    3.7     3.7                      
                               

Total contractual obligations

  $ 1,303.4   $ 96.0   $ 78.5   $ 75.5   $ 73.9   $ 72.6   $ 906.9  
                               

        The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

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Description of Indebtedness

        As of December 31, 2010 and 2009, long-term debt consisted of the following (in millions):

 
  2010   2009  

Prior credit facility, interest based on Prime and/or LIBOR plus an applicable margin interest rate at December 31, 2009 was 6.75%

  $   $ 529.6  

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin interest rate at December 31, 2010 was 4.0%

         

Senior secured notes (including PIK notes (1) of $9.5 million), weighted average interest rate at December 31 2009 was 10.5%

        326.0  

Senior unsecured notes, net of discount of $13.9 million, which bears interest at the rate of 8.875%

    711.5      

Series B secured note assumed in the Eunice transaction, which bears interest at the rate of 9.5%

    7.1     18.1  
           

    718.6     873.7  

Less current portion

    (7.1 )   (28.6 )
           
 

Debt classified as long-term

  $ 711.5   $ 845.1  
           

(1)
The senior secured notes began accruing additional interest of 1.25% per annum in February 2009 in the form of an increase in the principal amounts thereof (the "PIK notes"). These notes were paid in full in February 2010.

        Credit Facility.    In February 2010, the Partnership amended and restated its existing secured bank credit facility with a new syndicated secured bank credit facility. The credit facility has a borrowing capacity of $420.0 million and matures in February 2014. Net proceeds from the credit facility along with net proceeds from the senior unsecured notes discussed under "Senior Unsecured Notes" below were used to, among other things, repay the Partnership's prior credit facility and repay and retire all outstanding senior secured notes (including PIK notes) in February 2010. The Partnership recognized a loss on extinguishment of debt of $14.7 million when the debt was repaid due to make-whole interest payments on the senior secured debt of $9.3 million and the write-off of unamortized debt costs of $5.4 million. Debt refinancing costs totaling $26.7 million associated with new borrowings, including the senior unsecured notes, are included in other noncurrent assets as of December 31, 2010 and amortized to interest expense over the term of the related debt.

        As of December 31, 2010, there was $86.6 million in outstanding letters of credit, under the bank credit facility leaving approximately $333.4 million available for future borrowing.

        The credit facility is guaranteed by substantially all of the subsidiaries and is secured by first priority liens on substantially all of the Partnership's assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of its equity interests in substantially all of the Partnership's subsidiaries.

        The Partnership may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, extraordinary receipts, equity issuances and debt incurrences, but these mandatory prepayments do not require any reduction of the lenders' commitments under the credit facility.

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        Under the credit facility, borrowings bear interest at the Partnership's option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent's prime rate) plus an applicable margin. The Partnership pays a per annum fee on all letters of credit issued under the credit facility and a commitment fee of 0.50% per annum on the unused availability under the credit facility. The letter of credit fee and the applicable margins for the interest rate vary quarterly based on the Partnership's leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to adjusted EBITDA) and are as follows:

Leverage Ratio
  Base Rate Loans   Eurodollar Rate Loans   Letter of Credit Fees  

Greater than or equal to 5.00 to 1.00

    3.25 %   4.25 %   4.25 %

Greater than or equal to 4.50 to 1.00 and less than 5.00 to 1.00

    3.00 %   4.00 %   4.00 %

Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00

    2.75 %   3.75 %   3.75 %

Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00

    2.50 %   3.50 %   3.50 %

Less than 3.50 to 1.00

    2.25 %   3.25 %   3.25 %

        Based on the forecasted leverage ratio for 2011, the Partnership expects the applicable margin for the interest rate and letter of credit fee to be at the mid-point of these ranges. The credit facility does not have a floor for the Base Rate or the Eurodollar Rate.

        The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.

        The maximum permitted leverage ratio is as follows:

    5.25 to 1.00 for the fiscal quarter ending December 31, 2010;

    5.00 to 1.00 for the fiscal quarter ending March 31, 2011;

    4.75 to 1.00 for the fiscal quarter ending June 30, 2011; and

    4.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

        The maximum permitted senior leverage ratio (as defined in the credit facility, but generally computed as the ratio of total secured funded debt to adjusted EBITDA), is 2.50 to 1.00.

        The minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of adjusted EBITDA to consolidated interest charges) is as follows:

    1.75 to 1.00 for the fiscal quarter ending December 31, 2010;

    2.00 to 1.00 for the fiscal quarter ending March 31, 2011;

    2.25 to 1.00 for the fiscal quarter ending June 30, 2011; and

    2.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

        In addition, the credit facility contains various covenants that, among other restrictions, limit the Partnership's ability to:

    grant or assume liens;

    make investments;

    incur or assume indebtedness;

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    engage in mergers or acquisitions;

    sell, transfer, assign or convey assets;

    repurchase its equity, make distributions and certain other restricted payments;

    change the nature of its business;

    engage in transactions with affiliates;

    enter into certain burdensome agreements;

    make certain amendments to the omnibus agreement or its subsidiaries' organizational documents;

    prepay the senior unsecured notes and certain other indebtedness; and

    enter into certain hedging contracts.

        The credit facility permits the Partnership to make quarterly distributions to unitholders so long as no default exists under the new credit facility.

        Each of the following is an event of default under the credit facility:

    failure to pay any principal, interest, fees, expenses or other amounts when due;

    failure to meet the quarterly financial covenants;

    failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures;

    the failure of any representation or warranty to be materially true and correct when made;

    the Partnership or any of its subsidiaries default under other indebtedness that exceeds a threshold amount;

    judgments against the Partnership or any of its material subsidiaries, in excess of a threshold amount;

    certain ERISA events involving the Partnership or any of its material subsidiaries, in excess of a threshold amount;

    bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries; and

    a change in control (as defined in the credit facility).

        If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the credit facility will immediately become due and payable. If any other event of default exists under the credit facility, the lenders may accelerate the maturity of the obligations outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under the credit facility, the lenders may commence foreclosure or other actions against the collateral.

        If any default occurs under the credit facility, or if the Partnership is unable to make any of the representations and warranties in the credit facility, the Partnership will be unable to borrow funds or have letters of credit issued under the credit facility.

        The Partnership expects to be in compliance with the covenants in the credit facility for at least the next twelve months.

        Series B Secured Note.    On October 20, 2009, the Partnership acquired the Eunice natural gas liquids processing plant and fractionation facility which included an $18.1 million series B secured note.

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This note bears an interest rate of 9.5%. The Partnership paid $11.0 million in May 2010 and the remaining payment of $7.1 million is due in May 2011.

        Senior Unsecured Notes.    On February 10, 2010, the Partnership issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the "notes") due on February 15, 2018 at an issue price of 97.907% to yield 9.25% to maturity including the original issue discount (OID). Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and OID), together with borrowings under its credit facility discussed above, were used to repay in full amounts outstanding under its prior bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with the prior credit facility. Interest payments are due semi-annually in arrears in February and August.

        The indenture governing the notes contains covenants that, among other things, limit the Partnership's ability and the ability of certain of the Partnership's subsidiaries to:

    sell assets including equity interests in its subsidiaries;

    pay distributions on, redeem or repurchase units or redeem or repurchase its subordinated debt (as discussed in more detail below);

    make investments;

    incur or guarantee additional indebtedness or issue preferred units;

    create or incur certain liens;

    enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership;

    consolidate, merge or transfer all or substantially all of its assets;

    engage in transactions with affiliates;

    create unrestricted subsidiaries;

    enter into sale and leaseback transactions; or

    engage in certain business activities.

        The indenture provides that if the Partnership's fixed charge coverage ratio (the ratio of consolidated cash flow to fixed charges, which generally represents the ratio of adjusted EBITDA to interest charges with further adjustments as defined per the indenture) for the most recently ended four full fiscal quarters is not less than 2.0 to 1.0, the Partnership will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in the partnership agreement) with respect to its preceding fiscal quarter plus a number of items, including the net cash proceeds received by us as a capital contribution or from the issuance of equity interests since the date of the indenture, to the extent not previously expended. If its fixed charge coverage ratio is less than 2.0 to 1.0, the Partnership will be able to pay distributions to its unitholders in an amount equal to an $80.0 million basket (less amounts previously expended pursuant to such basket), plus the same number of items discussed in the preceding sentence to the extent not previously expended. The Partnership is in compliance with this ratio as of December 31, 2010.

        If the notes achieve an investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services, many of the covenants discussed above will terminate.

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        The Partnership may redeem up to 35% of the notes at any time prior to February 15, 2013 with the cash proceeds from equity offerings at a redemption price of 108.875% of the principal amount of the notes (plus accrued and unpaid interest to the redemption date) provided that:

    at least 65% of the aggregate principal amount of the senior notes remains outstanding immediately after the occurrence of such redemption; and

    the redemption occurs within 120 days of the date of the closing of the equity offering.

        Prior to February 15, 2014, the Partnership may redeem the notes, in whole or in part, at a "make-whole" redemption price. On or after February 15, 2014, the Partnership may redeem all or a part of the notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on February 15, 2014, 102.219% for the twelve-month period beginning February 15, 2015 and 100.00% for the twelve-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the notes.

        Each of the following is an event of default under the indenture:

    failure to pay any principal or interest when due;

    failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures;

    the Partnership or any of its subsidiaries' default under other indebtedness that exceeds a certain threshold amount;

    failures by us or any of its subsidiaries to pay final judgments that exceed a certain threshold amount; and

    bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries.

        If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies.

Credit Risk

        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 lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by its customers could adversely affect the results of operations and reduce the Partnership's ability to make distributions to its unitholders.

Inflation

        Inflation in the United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry experienced an increase in labor and material costs during 2008, but 2009 and 2010 remained relatively unchanged. These increases did not have a material impact on our results of operations for the periods presented. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

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Environmental

        The Partnership's operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe the Partnership is in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see Item 1. "Business—Environmental Matters."

Contingencies

        In December 2008, Denbury Onshore, LLC ("Denbury") initiated formal arbitration proceedings against Crosstex CCNG Processing Ltd. ("Crosstex Processing"), Crosstex Energy Services, L.P. ("Crosstex Energy"), Crosstex North Texas Gathering, L.P. ("Crosstex Gathering") and Crosstex Gulf Coast Marketing, Ltd. ("Crosstex Marketing"), all wholly-owned subsidiaries of the Partnership, asserting a claim for breach of contract under a gas processing agreement. Denbury alleged damages in the amount of $16.2 million, plus interest and attorneys' fees. Crosstex denied any liability and sought to have the action dismissed. An arbitration hearing was held in December 2009 and February 2010 Denbury was awarded $3.0 million plus interest, attorneys' fees and costs for its claims. The Partnership accrued an estimate of $3.7 million, reflecting the related expense in purchased gas costs for this award as of December 31, 2009. The final award totaling $3.5 million was paid in May 2010.

        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 24th Judicial District Court of Calhoun County, Texas, asserting claims for negligence, res ipsa loquitor, products liability and strict liability relating to the alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership. The lawsuit alleges that the plaintiffs have incurred at least $65.0 million in damages, including damage to equipment and lost profits. The Partnership has submitted the claim to its insurance carriers and intends to vigorously defend the lawsuit. The Partnership believes that any recovery would be within applicable policy limits. Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

        At times, the Partnership's 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.

        On October 23, 2006, Crosstex North Texas Gathering, L.P. filed a lawsuit against Robert L. Dow in the County Court at Law No. 1 of Tarrant County, Texas seeking a pipeline easement across portion of the defendant's sand and gravel mining operation. The court awarded the defendant $0.1 million in damages, but the defendant appealed and claimed damages for the taking, damages to the remainder of this property and damages due to lost profits from the sale of frac sand in excess of $90.0 million.

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On October 8, 2010, the Partnership settled this matter and received a pipeline easement in exchange for a payment of $6.75 million. This settlement was paid in 2010 and included as a property cost.

        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.

        On July 22, 2008, SemStream, L.P. and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As of July 22, 2008, SemStream, L.P. owed the Partnership approximately $6.2 million, including approximately $3.9 million for June 2008 sales and approximately $2.3 million for July 2008 sales. On or around April 6, 2010, the Partnership settled the administrative claim and received a payment of $2.1 million.

Disclosure Regarding Forward-Looking Statements

        This Annual Report on Form 10-K contains forward-looking statements that are based on information currently available to management as well as management's assumptions and beliefs. All statements, other than statements of historical fact, included in this Form 10-K constitute forward-looking statements, including but not limited to statements identified by the words "forecast," "may," "believe," "will," "should," "plan," "predict," "anticipate," "intend," "estimate" and "expect" and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Form 10-K, the risk factors set forth in "Item 1A. Risk Factors" may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk

        Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership's primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, it is also exposed to the risk of changes in interest rates on floating rate debt.

        On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") into law, a part of which relates to increased regulation of the markets for derivative products of the type the Partnership uses to manage areas of market risk. While the Commodity Futures Trading Commission has yet to issue regulations to implement this increased regulation, Dodd-Frank may result in increased costs to the Partnership to implement our market risk management strategy.

Interest Rate Risk

        The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At December 31, 2010, the Partnership had no outstanding borrowings under this facility.

        At December 31, 2010 and 2009, the Partnership had total fixed rate debt obligations of $718.6 million and $344.1 million, respectively. The balance at December 31, 2010 consists of the

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Partnership's senior unsecured notes with an interest rate of 8.875% and the series B secured note with an interest rate of 9.5%. The December 31, 2009 balance consisted of senior secured notes with a weighted average interest rate of 10.5% and the series B note with an interest rate of 9.5%. The fair value of these fixed rate obligations was approximately $768.3 million and $342.7 million as of December 31, 2010 and 2009, respectively. We estimate that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rate debt (the senior unsecured notes) by $30.1 million based on the debt obligations as of December 31, 2010.

Commodity Price Risk

        The Partnership 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. The Partnership currently processes gas under three main types of contractual arrangements:

    1.
    Processing margin contracts: 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 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 are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

    2.
    Percent of liquids 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. Therefore, its margins from these contracts are greater during periods of high liquids prices. The Partnership's margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

    3.
    Fee based contracts: Under these contracts the Partnership has no commodity price exposure and are paid a fixed fee per unit of volume that is processed.

        The gross operating margin presentation in the table below is calculated net of results from discontinued operations. Gas processing margins by contract types and gathering and transportation margins as a percent of total gross operating margin for the comparative year-to-date periods are as follows:

 
  Years ended December 31,  
 
  2010   2009   2008  

Gathering and transportation margin

    62.2 %   65.8 %   57.6 %

Gas processing margins:

                   
 

Processing margin

    12.9 %   8.9 %   15.4 %
 

Percent of liquids

    10.6 %   13.2 %   17.9 %
 

Fee based

    14.3 %   12.1 %   9.1 %
               
 

Total gas processing

    37.8 %   34.2 %   42.4 %

Total

    100.0 %   100.0 %   100.0 %
               

        The Partnership has hedges in place at December 31, 2010 covering a portion of the liquids volumes it expects to receive under percent of liquids (POL) contracts. The hedges done via swaps are

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set forth in the following table. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

Period   Underlying   Notional
Volume
  We Pay   We Receive*   Fair Value
Asset/(Liability)
 
 
   
   
   
   
  (In thousands)
 

January 2011—December 2011

  Ethane   122 (MBbls)   Index   $0.4880/gal   $ (339 )

January 2011—December 2011

  Propane     24 (MBbls)   Index   $1.0531/gal     (191 )

January 2011—December 2011

  Normal Butane     18 (MBbls)   Index   $1.4399/gal     (136 )

January 2011—December 2011

  Natural Gasoline     26 (MBbls)   Index   $1.7543/gal     (399 )
                       

*weighted average

                  $ (1,065 )
                       

        In addition, the Partnership has hedges in place covering 90 MBbls of Ethane for the final two quarters of 2011 done via the purchase of puts. The net fair value asset of the puts as of December 31, 2010 was less than $0.1 million.

        The Partnership has hedged its exposure to declines in prices for NGL volumes produced for its account. The NGL volumes hedged, as set forth above, focus on POL contracts. The Partnership hedges its POL exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total POL volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. The Partnership has hedged 60.9% of its hedgeable volumes at risk through December 2011 (24.9% of total volumes at risk through December 2011).

        The Partnership also has hedges in place at December 31, 2010 covering the fractionation spread risk related to its processing margin contracts as set forth in the following table:

Period   Underlying   Notional
Volume
  We Pay   We Receive   Fair Value
Asset/(Liability)
 
 
   
   
   
   
  (In thousands)
 

January 2011—December 2011

  Ethane   169 (MBbls)   Index   $ 0.5048/gal*   $ (312 )

January 2011—December 2011

  Propane     94 (MBbls)   Index   $ 1.1293/gal*     (435 )

January 2011—December 2011

  Iso Butane       6 (MBbls)   Index   $ 1.4991/gal*     (43 )

January 2011—December 2011

  Normal Butane     54 (MBbls)   Index   $ 1.5219/gal*     (219 )

January 2011—December 2011

  Natural Gasoline     55 (MBbls)   Index   $ 1.9272/gal*     (450 )

January 2011—December 2011

  Natural Gas   4,612 (MMBtu/d)   $4.536/MMBtu*     Index     (87 )
                         

*weighted average

                    $ (1,546 )
                         

        In relation to its fractionation spread risk, as set forth above, the Partnership has hedged 57.8% of its hedgeable liquids volumes at risk through December 2011 (21.4% of total liquids volumes at risk) and 60.8% of the related hedgeable PTR volumes through December 2011 (22.3% of total PTR volumes).

        The Partnership is also subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transport services. Approximately 7.6% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the natural gas at a percentage of the index price, the Partnership's resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices.

        Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves the Partnership with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

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        The Partnership's primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

        The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

        As of December 31, 2010, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $2.4 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in an increase of approximately $2.0 million in the net fair value liability of these contracts as of December 31, 2010 to a net fair value liability of approximately $4.4 million.

Item 8.    Financial Statements and Supplementary Data

        The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-49 of this Report and are incorporated herein by reference.

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

        None.

Item 9A.    Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

        We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (December 31, 2010), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding disclosure.

(b) Changes in Internal Control Over Financial Reporting

        There has been no change in our internal control over financial reporting that occurred in the three months ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Internal Control Over Financial Reporting

        See "Management's Report on Internal Control over Financial Reporting" on page F-2.

Item 9B.    Other Information

        None.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

        The following table shows information about our executive officers. Executive officers serve until their successors are elected or appointed.

Name
  Age   Position with Crosstex Energy GP, LLC
Barry E. Davis(1)     49   President, Chief Executive Officer and Director
William W. Davis(1)     57   Executive Vice President and Chief Financial Officer
Joe A. Davis(1)     50   Executive Vice President, General Counsel and Secretary
Michael J. Garberding     42   Senior Vice President—Finance
Stan Golemon     47   Senior Vice President—Engineering and Operations
Steven R. Spaulding     45   Senior Vice President—Processing and NGLs

(1)
Not related.

        Barry E. Davis, President, Chief Executive Officer and Director, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of our predecessor. Mr. Davis has served as director since our IPO in December 2002. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis holds a B.B.A. in Finance from Texas Christian University. Mr. Davis also serves as Chairman of the Board for Crosstex Energy, Inc. Mr. Davis is not related to William W. Davis or Joe A. Davis.

        William W. Davis, Executive Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has over 30 years of finance and accounting experience. For more than the last seven years, Mr. Davis has served as our Chief Financial Officer. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant. Mr. Davis is not related to Barry E. Davis or Joe A. Davis.

        Joe A. Davis, Executive Vice President, General Counsel and Secretary, joined Crosstex in October 2005. He began his legal career in 1985 with the Dallas firm of Worsham Forsythe, which merged with the international law firm of Hunton & Williams in 2002. Most recently, he served as a partner in the firm's Energy Practice Group, and served on the firm's Executive Committee. Mr. Davis specialized in facility development, sales, acquisitions and financing for the energy industry, representing entrepreneurial start up/development companies, growth companies, large public corporations and large electric and gas utilities. He received his J.D. from Baylor Law School in Waco and his B.S. degree from the University of Texas in Dallas. Mr. Davis is not related to Barry E. Davis or William W. Davis.

        Michael J. Garberding, Senior Vice President—Finance joined our general partner in February 2008. Mr. Garberding has 20 years experience in finance and accounting. From 2002 to 2008, Mr. Garberding held various finance and business development positions at TXU Corporation including assistant treasurer. In addition, Mr. Garberding worked at Enron North America as a Finance Manager and Arthur Andersen LLP as an Audit Manager. He received his Masters in Business Administration from the University of Michigan in 1999 and his B.B.A. in Accounting from Texas A&M University in 1991.

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        Steven R. Spaulding, Senior Vice President—Processing and NGLs joined our general partner in April of 2010. Mr. Spaulding has 20 years of experience in engineering, operations, and commercial development in the midstream industry. From 1990 to 2010, Mr. Spaulding held various midstream engineering, commercial, and management positions with Chevron, including Manager of Equity NGL Supply and Trading and Midstream Commercial and Business Development Manager. Mr. Spaulding graduated from the University of Oklahoma with a Bachelor of Science degree in Chemical Engineering.

        Stan Golemon, Senior Vice President—Engineering and Operations, joined our general partner in May of 2008. Mr. Golemon has 25 years of experience in engineering, operations, and commercial development in the midstream and exploration and production industries. From 1997 to 2008, Mr. Golemon held various midstream engineering, commercial, and management positions with Union Pacific Resources and its successor company Anadarko Petroleum Corporation including General Manager of Midstream Engineering and Engineering Supervisor. Mr. Golemon also spent 3 years with The Arrington Corporation consulting on sulfur recovery operations and Process Safety Management. Mr. Golemon began his career with ARCO Oil and Gas Company where he worked in plant, onshore facilities, and offshore facilities engineering. Mr. Golemon graduated summa cum laude from Louisiana Tech University in 1985 with a Bachelor of Science degree in Chemical Engineering.

Code of Ethics

        We adopted a Code of Business Conduct and Ethics (the "Code of Ethics") applicable to all of our employees, officers, and directors, with regard to company-related activities. The Code of Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. The Code of Ethics also incorporates our expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications. A copy of the Code of Ethics is available to any person, free of charge, at our web site: www.crosstexenergy.com. If any substantive amendments are made to the Code of Ethics or if we grant any waiver, including any implicit waiver, from a provision of the Code of Ethics to any of our executive officers and directors, we will disclose the nature of such amendment or waiver on our web site.

Other

        The sections entitled "Proposal One: Election of Directors," "Additional Information Regarding the Board of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Stockholder Proposals and Other Matters" that will appear in our proxy statement for the 2011 annual meeting of stockholders, which we expect to file with the Securities and Exchange Commission within 120 days after December 31, 2010 (the "2011 Proxy Statement"), will set forth certain information with respect to our directors and with respect to reporting under Section 16(a) of the Securities Exchange Act of 1934, and are incorporated herein by reference.

Item 11.    Executive Compensation

        The section entitled "Executive Compensation" that will appear in the 2011 Proxy Statement will set forth certain information with respect to the compensation of our management, and is incorporated herein by reference.

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

        The sections entitled "Equity Compensation Plans" and "Security Ownership of Certain Beneficial Owners and Management" that appears in the 2011 Proxy Statement will set forth certain information

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with respect to securities authorized for issuance under equity compensation plans and the ownership of voting securities and equity securities of us, and are incorporated herein by reference.

Item 13.    Certain Relationships and Related Transactions and Director Independence

        The sections entitled "Certain Relationships and Related Party Transactions" and "Additional Information Regarding the Board of Directors" that will appear in the 2011 Proxy Statement will set forth certain information with respect to certain relationships and related party transactions, and are incorporated herein by reference.

Item 14.    Principal Accounting Fees and Services

        The section entitled "Fees Paid to Independent Public Accounting Firm" that will appear in the 2011 Proxy Statement will set forth certain information with respect to accounting fees and services, and is incorporated herein by reference.

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PART IV

Item 15.    Exhibits and Financial Statement Schedules

(a)
Financial Statements and Schedules

(1)
See the Index to Financial Statements on page F-1.

(2)
Schedule I—Parent Company Statements on page F-49 and Schedule II—Valuation and Qualifying Accounts on page F-52.

(3)
Exhibits

        The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Number    
  Description
  2.1**       Partnership Interest Purchase and Sale Agreement, dated as of June 9, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex CCNG Gathering, Ltd., Crosstex CCNG Transmission Ltd., Crosstex Gulf Coast Transmission Ltd., Crosstex Mississippi Pipeline, L.P., Crosstex Mississippi Gathering, L.P., Crosstex Mississippi Industrial Gas Sales, L.P., Crosstex Alabama Gathering System, L.P., Crosstex Midstream Services, L.P., Javelina Marketing Company Ltd., Javelina NGL Pipeline Ltd. and Southcross Energy LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated June 9, 2009, filed with the Commission on June 11, 2009, file No. 000-50067).
  2.2**       Partnership Interest Purchase and Sale Agreement, dated as of August 28, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex Treating Services, L.P. and KM Treating GP LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated August 28, 2009, filed with the Commission on September 3, 2009, file No. 000-50067).
  3.1       Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006, file No. 000-50536).
  3.2       Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006, file No. 000-50536).
  3.3       Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
  3.4       Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007, file No. 000-50067).
  3.5       Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007, file No. 000-50067).

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Number    
  Description
  3.6       Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008, file No. 000-50067).
  3.7       Amendment No. 3 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of January 19, 2010 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010, file No. 000-50067).
  3.8       Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
  3.9       Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 000-50067).
  3.10       Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
  3.11       Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
  3.12       Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of January 19, 2010 (incorporated by reference to Exhibit 3.2 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010, file No. 000-50067).
  4.1       Specimen Certificate representing shares of common stock (incorporated by reference from Exhibit 4.1 to our Registration Statement on Form S-1, file No. 333-110095).
  4.2       Registration Rights Agreement, dated as of January 19, 2010, by and among Crosstex Energy, L.P. and GSO Crosstex Holdings LLC (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010, file No. 000-50067).
  4.3       Indenture, dated as of February 10, 2010, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010, file No. 000-50067).
  4.4       Registration Rights Agreement, dated as of February 10, 2010, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010, file No. 000-50067).
  10.1†       Crosstex Energy, Inc. Amended and Restated Long-Term Incentive Plan effective as of September 6, 2006 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006, file No. 000-50536).

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Number    
  Description
  10.2†       Crosstex Energy GP, LLC Amended and Restated Long-Term Incentive Plan, dated March 17, 2009 (incorporated by reference to Exhibit 10.3 to Crosstex Energy, L.P.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, file No. 000-50067).
  10.3†       Crosstex Energy, Inc. 2009 Long-Term Incentive Plan, effective March 17, 2009 (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, file No. 000-50536).
  10.4       Omnibus Agreement, dated December 17, 2002, among Crosstex Energy, L.P. and certain other parties (incorporated by reference to Exhibit 10.5 to Crosstex Energy, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2002, file No. 000-50067).
  10.5†       Form of Employment Agreement (incorporated by reference to Exhibit 10.6 to Crosstex Energy, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2002, file No. 000-50067).
  10.6†       Form of Severance Agreement (incorporated by reference to Exhibit 10.6 to Crosstex Energy, L.P.'s Annual Report on Form 10K for the year ended December 31, 2009, file No. 000-50067).
  10.7†       Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007, file No. 000-50067).
  10.8†       Form of Performance Share Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007, file No. 000-50536).
  10.9†       Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.9 to our Annual Report on Form 10-K for the year ended December 31, 2009, file No. 000-50067).
  10.10†       Form of Restricted Unit Agreement (incorporated by reference to Exhibit 10.9 to Crosstex Energy, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2009, file No. 000-50067).
  10.11†       Form of Indemnity Agreement (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the year ended December 31, 2003, file No. 000-50536).
  10.12       Board Representation Agreement, dated as of January 19, 2010, by and among Crosstex Energy GP, LLC, Crosstex Energy GP, L.P., Crosstex Energy, L.P., Crosstex Energy, Inc. and GSO Crosstex Holdings LLC (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010, file No. 000-50067).
  10.13       Purchase Agreement, dated as of February 3, 2010, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated February 3, 2010, filed with the Commission on February 5, 2010, file No. 000-50067).
  10.14       Amended and Restated Credit Agreement, dated as of February 10, 2010, by and among Crosstex Energy, L.P., Bank of America, N.A., as Administrative Agent and L/C Issuer thereunder, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010, file No. 000-50067).

81


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Number    
  Description
  10.15       Series A Convertible Preferred Unit Purchase Agreement, dated as of January 6, 2010, by and between Crosstex Energy, L.P. and GSO Crosstex Holding LLC (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 6, 2010, filed with the Commission on February 11, 2010, file No. 000-50067).
  10.16       Agreement Regarding 2003 Registration Statement and Waiver and Termination of Stockholders' Agreement, dated October 27, 2003 (incorporated by reference from Exhibit 10.4 to our Annual Report on Form 10-K for the year ended December 31, 2003, file No. 000-50536).
  10.17       Registration Rights Agreement, dated December 31, 2003 (incorporated by reference from Exhibit 10.6 to our Annual Report on Form 10-K for the year ended December 31, 2003, file No. 000-50536).
  21.1*       List of Subsidiaries.
  23.1*       Consent of KPMG LLP.
  31.1*       Certification of the Principal Executive Officer.
  31.2*       Certification of the Principal Financial Officer.
  32.1*       Certification of the Principal Executive Officer and the Principal Financial Officer of the Company pursuant to 18 U.S.C. Section 1350.

*
Filed herewith.

**
In accordance with the instructions to item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1 and 2.2 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.

As required by Item 15(a)(3), this exhibit is identified as a compensatory benefit plan or arrangement.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of February 2011.

    CROSSTEX ENERGY, INC.

 

 

By:

 

/s/ BARRY E. DAVIS

Barry E. Davis,
President and Chief Executive Officer

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

Signature
 
Title
 
Date

 

 

 

 

 
/s/ BARRY E. DAVIS

Barry E. Davis
  President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
  February 25, 2011

/s/ LELDON E. ECHOLS

Leldon E. Echols

 

Director

 

February 25, 2011

/s/ JAMES C. CRAIN

James C. Crain

 

Director

 

February 25, 2011

/s/ BRYAN H. LAWRENCE

Bryan H. Lawrence

 

Director

 

February 25, 2011

/s/ SHELDON B. LUBAR

Sheldon B. Lubar

 

Director

 

February 25, 2011

/s/ CECIL E. MARTIN

Cecil E. Martin

 

Director

 

February 25, 2011

/s/ ROBERT F. MURCHISON

Robert F. Murchison

 

Director

 

February 25, 2011

/s/ WILLIAM W. DAVIS

William W. Davis

 

Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

 

February 25, 2011

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INDEX TO FINANCIAL STATEMENTS

Crosstex Energy, Inc. Consolidated Financial Statements:

   

Management's Report on Internal Control Over Financial Reporting

 
F-2

Reports of Independent Registered Public Accounting Firm

 
F-3

Consolidated Balance Sheets as of December 31, 2010 and 2009

 
F-5

Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008

 
F-6

Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2010, 2009 and 2008

 
F-7

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008

 
F-8

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

 
F-9

Notes to Consolidated Financial Statements

 
F-10

Crosstex Energy, Inc. Financial Statement Schedules:

   

Schedule I—Parent Company Statements:

   

Condensed Balance Sheets as of December 31, 2010 and 2009

 
F-49

Condensed Statements of Operations for the years ended December 31, 2010, 2009 and 2008

 
F-50

Condensed Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

 
F-51

Schedule II—Valuation and Qualifying Accounts:

   

Valuation and Qualifying Accounts as of December 31, 2010 and 2009

 
F-52

F-1


Table of Contents


MANAGEMENT'S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING

        Management of Crosstex Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for Crosstex Energy, Inc (the "Company"). As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of Crosstex Energy Inc.'s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.

        The Company's internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company's transactions and dispositions of the Company's assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorization of the Company's management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.

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

        In connection with the preparation of the Company's annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management's assessment included an evaluation of the design of the Company's internal control over financial reporting and testing of the operational effectiveness of those controls.

        Based on this assessment, management has concluded that as of December 31, 2010, the Company's internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

        KPMG LLP, the independent registered public accounting firm that audited the Company's consolidated financial statements included in this report, has issued an attestation report on the Company's internal control over financial reporting, a copy of which appears on page F-3 of this Annual Report on Form 10-K.

F-2


Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and the Stockholders of
Crosstex Energy, Inc:

        We have audited the accompanying consolidated balance sheets of Crosstex Energy, Inc (a Delaware corporation) and subsidiaries as of December 31, 2010 and 2009 and the related consolidated statements of operations, changes in stockholders' equity, comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedules. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Crosstex Energy, Inc and subsidiaries as of December 31, 2010 and 2009 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

    /s/ KPMG LLP

Dallas, Texas
February 25, 2011

 

 

F-3


Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and the Stockholders of
Crosstex Energy, Inc:

        We have audited Crosstex Energy, Inc and subsidiaries' internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

        In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders' equity, comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements.

    /s/ KPMG LLP

Dallas, Texas
February 25, 2011

 

 

F-4


Table of Contents


CROSSTEX ENERGY, INC.

Consolidated Balance Sheets

 
  December 31,  
 
  2010   2009  
 
  (In thousands, except share data)
 

ASSETS

             

Current assets:

             
 

Cash and cash equivalents

  $ 22,780   $ 10,703  

Accounts receivable:

             
 

Trade, net of allowance for bad debts of $163 and $410, respectively

    16,217     27,434  
 

Accrued revenues

    190,726     180,221  
 

Imbalances

    2,920     6,020  
 

Other

    135     1,075  
 

Fair value of derivative assets

    5,523     9,112  
 

Natural gas and natural gas liquids, prepaid expenses and other

    9,780     14,692  
           
   

Total current assets

    248,081     249,257  
           

Property and equipment:

             
 

Transmission assets

    383,651     382,965  
 

Gathering systems

    623,451     605,981  
 

Gas plants

    461,865     457,139  
 

Other property and equipment

    56,231     80,476  
 

Construction in process

    20,709     12,693  
           
   

Total property and equipment

    1,545,907     1,539,254  
 

Accumulated depreciation

    (329,741 )   (259,057 )
           
   

Total property and equipment, net

    1,216,166     1,280,197  
           

Fair value of derivative assets

    1,169     5,665  

Intangible assets, net of accumulated amortization of $151,735 and $115,813, respectively

    498,975     534,897  

Other assets, net

    26,712     10,217  
           

Total assets

  $ 1,991,103   $ 2,080,233  
           

LIABILITIES AND STOCKHOLDERS' EQUITY

             

Current liabilities:

             
 

Drafts payable

    151     5,214  
 

Accounts payable

    15,988     17,978  
 

Accrued gas purchases

    160,909     150,816  
 

Accrued imbalances payable

    1,889     5,702  
 

Fair value of derivative liabilities

    7,980     30,337  
 

Current portion of long-term debt

    7,058     28,602  
 

Other current liabilities

    66,887     52,399  
           
   

Total current liabilities

    260,862     291,048  
           

Long-term debt

    711,512     845,100  

Other long-term liabilities

    26,879     20,797  

Deferred tax liability

    89,216     95,272  

Fair value of derivative liabilities

    1,156     12,106  

Commitments and contingencies

         

Stockholders' equity:

             
 

Common stock (150,000,000 shares authorized, $.01 par value, 46,894,859 and 46,524,177 issued and outstanding in 2010 and 2009, respectively)

    468     464  
 

Additional paid-in capital

    242,390     271,669  
 

Accumulated deficit

    (58,298 )   (43,279 )
 

Accumulated other comprehensive loss

    (145 )   (568 )
           
   

Total Crosstex Energy, Inc. stockholders' equity

    184,415     228,286  
 

Interest of non-controlling partners in the Partnership

    717,063     587,624  
           
 

Total stockholders' equity

    901,478     815,910  
           
 

Total liabilities and stockholders' equity

  $ 1,991,103   $ 2,080,233  
           

See accompanying notes to consolidated financial statements.

F-5


Table of Contents


CROSSTEX ENERGY, INC.

Condensed Consolidated Statements of Operations

 
  Years ended December 31,  
 
  2010   2009   2008  
 
  (In thousands, except per unit data)
 

Revenues:

                   
 

Midstream

  $ 1,792,676   $ 1,583,551   $ 3,558,213  
               
   

Total revenues

    1,792,676     1,583,551     3,558,213  
               

Operating costs and expenses:

                   
 

Purchased gas and NGLs

    1,454,376     1,272,329     3,250,427  
 

Operating expenses

    105,060     110,394     125,762  
 

General and administrative

    51,172     62,491     72,377  
 

Gain on sale of property

    (13,881 )   (666 )   (947 )
 

(Gain) loss on derivatives

    9,100     (2,994 )   (8,619 )
 

Impairments

    1,311     2,894     30,177  
 

Depreciation and amortization

    111,625     119,162     107,652  
               
   

Total operating costs and expenses

    1,718,763     1,563,610     3,576,829  
               
 

Operating income (loss)

    73,913     19,941     (18,616 )

Other income (expense):

                   
 

Interest expense, net of interest income

    (87,028 )   (95,078 )   (74,861 )
 

Loss on extinguishment of debt

    (14,713 )   (4,669 )    
 

Other income

    294     1,449     27,898  
               
   

Total other income (expense)

    (101,447 )   (98,298 )   (46,963 )
               
 

Loss from continuing operations before income taxes and gain on issuance of Partnership units

    (27,534 )   (78,357 )   (65,579 )
 

Income tax benefit from continuing operations

    6,021     6,020     1,375  
 

Gain on issuance of Partnership units

            14,748  
               
 

Loss from continuing operations

    (21,513 )   (72,337 )   (49,456 )
               

Discontinued operations:

                   
 

Income (loss) from discontinued operations, net of tax of $0, $255 and
$(3,541), respectively

        (1,519 )   21,466  
 

Gain on sale of discontinued operations, net of tax of $0, $(23,735) and
$(7,053), respectively

        159,961     42,753  
               
 

Discontinued operations, net of tax

        158,442     64,219  
               

Net income (loss)

    (21,513 )   86,105     14,763  
               

Less: Interest of non-controlling partners in the Partnership's net income (loss):

                   
 

Interest of non-controlling partners in the Partnership's continuing operations

    (9,862 )   (48,069 )   (55,704 )
 

Interest of non-controlling partners in the Partnership's discontinued operations

        (1,137 )   15,454  
 

Interest of non-controlling partners in the Partnership's gain on sale of discontinued operations

        119,669     30,780  
               
 

Total interest of non-controlling partners in the Partnership's net income (loss)

    (9,862 )   70,463     (9,470 )
               

Net income (loss) attributable to Crosstex Energy, Inc. 

  $ (11,651 ) $ 15,642   $ 24,233  
               

Net income (loss) per common share:

                   
 

Basic

  $ (0.24 ) $ 0.33   $ 0.52  
               
 

Diluted

  $ (0.24 ) $ 0.33   $ 0.51  
               

Weighted-average shares outstanding:

                   
 

Basic

    46,732     46,476     46,298  
 

Diluted

    46,732     46,535     46,589  

Dividend per share:

                   
 

Common

  $ 0.07   $ 0.09   $ 1.32  

Amount attributable to Crosstex Energy, Inc. common shareholders:

                   
 

Income (loss) from continuing operations, net of tax and non-controlling interest

  $ (11,651 ) $ (24,267 ) $ 6,249  
 

Income (loss) from discontinued operations, net of tax and non-controlling interest

        (383 )   6,011  
 

Gain on sale of discontinued operations, net of tax and non-controlling interest

        40,292     11,973  
               

Net income (loss) attributable to Crosstex Energy, Inc. 

  $ (11,651 ) $ 15,642   $ 24,233  
               

See accompanying notes to consolidated financial statements.

F-6


Table of Contents


CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders' Equity

Years ended December 31, 2010, 2009 and 2008

 
  Common Stock    
   
  Accumulated
Other
Comprehensive
Income (loss)
   
   
 
 
  Additional
Paid-In
Capital
  Retained
Earnings
(Deficit)
  Non-
Controlling
Interest
  Total
Stockholders'
Equity
 
 
  Shares   Amount  
 
  (In thousands)
 

Balance, December 31, 2007

    46,019   $ 463   $ 267,859   $ (16,878 ) $ (5,078 ) $ 489,034   $ 735,400  

Conversion of restricted stock for common, net of shares withheld for taxes

    285         (3,815 )               (3,815 )

Proceeds from exercise of stock options

    38     1     243                 244  

Stock-based compensation

            4,701             6,578     11,279  

Common dividends

                (62,048 )           (62,048 )

Net income (loss)

                24,233         (9,470 )   14,763  

Non-controlling partner's share of other comprehensive income in Partnership

                    431         431  

Hedging gains or losses reclassified to earnings

                    4,689     13,402     18,091  

Adjustment in fair value of derivatives

                    628     2,747     3,375  

Contribution from non-controlling interest

                        83,820     83,820  

Distribution to non-controlling interest

                        (63,150 )   (63,150 )
                               

Balance, December 31, 2008

    46,342     464     268,988     (54,693 )   670     522,961     738,390  

Offering costs

            (42 )               (42 )

Conversion of restricted stock for common, net of shares withheld for taxes

    182         (354 )               (354 )

Stock-based compensation

            3,077            <