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TABLE OF CONTENTS

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K

Commission file number: 000-50067

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

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

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

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

        Indicate by check mark whether registrant 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, and has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. ý

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

        The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $74,396,675 on June 30, 2003, based on $32.81 per unit, the closing price of the Common Units as reported on the NASDAQ National Market on such date.

        At February 28, 2004, there were outstanding 4,358,000 Common Units and 4,667,000 Subordinated Units.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

DESCRIPTION

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CROSSTEX ENERGY, L.P.

PART I

Item 1. Business

General

        Crosstex Energy, L.P. is a publicly traded Delaware limited partnership, formed in July 2002 in connection with its initial public offering, which was completed in December 2002. Our Common Units are listed on the NASDAQ National Market. Our business activities are conducted through our subsidiary, Crosstex Energy Services, L.P., a Delaware limited partnership (the "Operating Partnership") and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our telephone number is (214) 953-9500. In this report, the terms "Partnership" and "Registrant," as well as the terms "our," "we," and "its," are sometimes used as abbreviated references to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. and its consolidated subsidiaries, including the Operating Partnership.

        We are a rapidly growing independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas. We connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities to ensure that it meets pipeline quality specifications, process natural gas for the removal of natural gas liquids or NGLs, transport natural gas and ultimately provide an aggregated supply of natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generate gross margins based on the difference between the purchase and resale prices. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee.

        Our major assets include over 2,500 miles of natural gas gathering and intrastate transmission pipelines, three natural gas processing plants connected to our gathering systems with a total NGL production capacity of 289,800 gallons per day and 61 natural gas treating plants. Our gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plants remove NGLs from a natural gas stream and fractionate, or separate, the NGLs into separate NGL products, including ethane, propane, mixed butanes and natural gasoline. Our natural gas treating plants, located largely in the Texas Gulf Coast area, remove impurities from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications.

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        Set forth in the table below is a list of our significant acquisitions since January 2000.

(1)

Certain Gulf Coast customers are now provided service through the Vanderbilt system.

(2)

Represents average throughput from the acquisition date, June 30, 2003, through December 31, 2003.

        We have two operating segments, Midstream and Treating. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. See Note 13 to the consolidated financial statements for financial information about these operating segments.

        Our general partner interest is held by Crosstex Energy GP, L.P., a Delaware limited partnership. Crosstex Energy GP, LLC, a Delaware limited liability company, is Crosstex Energy GP, L.P.'s general partner. Crosstex Energy GP, LLC manages our operations and activities and employs our officers.

        References in this report to "our predecessor" refer to Crosstex Energy Services, Ltd., a Texas limited partnership, substantially all of the assets of which were transferred to the Partnership at the closing of our initial public offering.

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

/d = per day
Btu = British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet

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Business Strategy

        Our strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation, and marketing of natural gas; improving the profitability of our owned assets by increasing their utilization while controlling costs; accomplishing economies of scale through new construction or expansion in core operating areas; and maintaining financial flexibility to take advantage of opportunities. Our strategy is based on our expectation of a continued high level of drilling in our principal geographic areas and a process of ongoing divestitures of gas transportation and processing assets by large industry participants. We believe these two factors should present opportunities for continued expansion in our existing areas of operation as well as opportunities to acquire assets in new geographic areas that may serve as a platform for future growth. Key elements of our strategy include the following:

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Pursuing accretive acquisitions.    We intend to use our acquisition and integration experience to continue to make strategic acquisitions of midstream assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset. We pursue acquisitions that we believe will add to existing core areas in order to capitalize on our existing infrastructure, personnel, and producer and consumer relationships. We also examine opportunities to establish new core areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. We plan to establish new core areas primarily through the acquisition of key assets that will serve as a platform for further growth both through additional acquisitions and the construction of new assets. A recent example of establishing a new core area includes the Mississippi pipeline system acquired as part of the DEFS acquisition. This system provides us with a platform to develop a significant presence in the south central Mississippi area.



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Improving existing system profitability.    After we acquire or construct a new system, we begin an aggressive effort to market services directly to both producers and end users in order to connect new supplies of natural gas, improve margins, and fully utilize the system's capacity. Many of our recently acquired systems have excess capacity that provides us opportunities to increase throughput with minimal incremental cost. As part of this process, we focus on providing a full range of services to small and medium size independent producers and end users, including supply aggregation, transportation and hedging, which we believe provides us with a competitive advantage when we compete for sources of natural gas supply. Additionally, we emphasize increasing the percentage of our natural gas sales directly to end users, such as industrial and utility consumers in an effort to increase our operating margins. For the year ended December 31, 2003, approximately 58% of our on-system natural gas sales were to industrial end users and utilities.



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Undertaking construction and expansion opportunities.    We leverage our existing infrastructure and producer and customer relationships by constructing and expanding systems to meet new or increased demand for our gathering, transmission, treating, processing and marketing services. These projects include expansion of existing systems and construction of new facilities. As an example, we enhanced the Gregory system by acquiring the Koch Ingleside Pipeline and connecting directly to a major end user customer. Our 2002 acquisition of the Hallmark Lateral facilitated the establishment of connections between our Corpus Christi and our Gulf Coast systems which has increased our flexibility in balancing gas supply and market requirements throughout the regions covered. In August 2003, we expanded the capacity of our Gregory processing plant from 99,900 MMBtu/d to 166,500 MMBtu/d, a 67% increase over its previous capacity, and began marketing the additional gas through our Corpus Christi and Gulf Coast systems.

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Recent Acquisitions and Expansion

        Duke Energy Field Services.    In June 2003, we acquired various midstream assets located in Mississippi, Texas, Alabama and Louisiana from DEFS for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. The acquisition provided us with a new core area for growth in south central Mississippi, expanded our presence in West Texas, increased the total miles of our pipelines from 1,700 to 2,500 and enabled us to enter the business of carbon dioxide separation. In addition, we believe that the acquisition has increased the stability of our cash flow as operating profits from the Mississippi pipeline system are generated through purchasing, gathering, transporting and reselling natural gas which generates margins not affected by commodity prices, and a majority of the income we receives from the Seminole gas plant is based on fixed fees for carbon dioxide separation and sulfur removal.

        Gregory Expansion.    In August 2003, we completed an expansion of our Gregory processing plant. The expansion increased the plant capacity from approximately 99,900 MMBtu/d to 166,500 MMBtu/d, at a cost of approximately $7.0 million. In addition, we have significantly reduced our exposure to commodity prices by renegotiating a number of our commodity based contracts, where revenues were subject to fluctuating commodity prices, to fee-based contracts. See Item 2. "Properties."

        Subsequent Event.    We entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power for $76.2 million. The acquisition will increase the Partnership's pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. We will finance the acquisition through borrowings under our existing bank credit facility, issuance of additional senior notes or other financing alternatives.

Other Developments

        Two-For-One Split of Limited Partnership Units.    On February 26, 2004, we announced a two-for-one split on our outstanding limited partnership units. The unit split will entitle unit holders of record at the close of business on March 16, 2004 to receive one additional limited partnership unit for every unit held. All unit amounts in this Annual Report on Form 10-K reflect pre-split units.

        Initial Public Offering of Crosstex Energy, Inc.    Our general partner, Crosstex Energy GP, L.P., is an indirect wholly owned subsidiary of Crosstex Energy, Inc. ("CEI"). In January 2004, CEI completed an initial public offering of its common shares pursuant to which its existing shareholders, including CES management and directors, sold a portion of their common shares with public shareholders now owning 22.0% of CEI.

        Our Follow-on Offering.    In September 2003, we completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. We received net proceeds of approximately $59.1 million, including an approximate $1.3 million capital contribution by the general partner. The net proceeds were used to repay borrowings outstanding under the bank credit facility of our operating partnership.

        Bank Credit Facility.    In June 2003, our operating partnership, Crosstex Energy Services, L.P., entered into a new $100.0 million senior secured credit facility, which was increased to $120 million in October 2003, consisting of a $70.0 million acquisition facility and a $50.0 million working capital and letter of credit facility. As of December 31, 2003, the operating partnership had $20.0 million of

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outstanding borrowings under the acquisition facility and $30.3 million of letters of credit issued under the working capital and letter of credit facility. The credit facility matures in June 2006.

        Secured Secured Notes.    In June 2003, the operating partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, the operating partnership issued $10.0 million of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years. The senior secured notes are guaranteed by the operating partnership's subsidiaries and us. The operating partnership used the net proceeds from the senior notes offering to repay indebtedness under its bank credit facility.

Midstream Division

        Gathering and Transmission.    Our primary Midstream assets include systems located primarily along the Texas Gulf Coast and in south-central Mississippi, which, in the aggregate, consist of approximately 2,500 miles of pipeline and three processing plants and contributed approximately 78% and 72% of our gross profit in 2003 and 2002, respectively.

•

Gulf Coast System.    The Gulf Coast system is an intrastate pipeline system consisting of approximately 484 miles of gathering and transmission pipelines with a mainline from Refugio County in south Texas running northeast along the Gulf Coast to the Brazos River in Fort Bend County near Houston. The system's gathering and transmission pipelines range in diameter from 4 to 20 inches. We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million.

The Gulf Coast system has two supply pipeline laterals which connect to gathering systems which collect natural gas from approximately 80 receipt points and five treating and processing plants operated by third parties. This system has three delivery laterals which deliver natural gas directly to large industrial and utility consumers along the Gulf Coast. The system interconnects with multiple third party pipelines through which we may purchase volumes not gathered through our systems for resale or through which we might deliver natural gas to customers which are not connected to our system. We transport gas on the TXU Lone Star pipeline providing access for our Gulf Coast mainline system in Fort Bend County to the Katy hub, a major natural gas physical exchange that allows access to seven third party pipelines, including Kinder Morgan, TECO and Trunkline. The Gulf Coast system has a capacity of 210,600 MMBtu/d and average throughput on this system was approximately 85,000 MMBtu/d for the year ended December 31, 2003.

We generate operating profits in our Gulf Coast system through the margins we earn by purchasing, gathering, transporting and reselling natural gas. We purchase natural gas from a producer, pipeline or marketing company and then transport and resell the gas. As of December 31, 2003, we were purchasing gas from over 70 producers primarily pursuant to month-to-month contracts and were reselling the natural gas to approximately 10 customers primarily pursuant to short-term or month-to-month arrangements. For the year ended December 31, 2003, approximately 92% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder was purchased at a percentage of an index, and all the natural gas volumes we sold were sold at a fixed price relative to an index.

•

Vanderbilt System.    Our Vanderbilt system consists of approximately 200 miles of gathering and transmission pipelines located in Wharton and Fort Bend Counties near our Gulf Coast system. Natural gas is supplied to the system from over 27 receipt points. The gas had been sold to the Exxon Katy plant and, in June 2003, we reversed the flow of gas and began deliveries to the Formosa Hydrocarbons processing plant at Point Comfort, Texas. Our Vanderbilt system has a capacity of 141,700 MMBtu/d and average throughput was approximately 49,000 MMBtu/d for

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the year ended December 31, 2003. We acquired the Vanderbilt system in December 2002 for a purchase price of $12.0 million.

All the gas in the Vanderbilt system is now sold to Formosa Hydrocarbons under a ten year agreement which began in June 2003 to supply up to 60,000 MMBtu/d. The gas is sold to Formosa at a fixed price relative to an index. Gas is purchased from approximately 15 producers, primarily pursuant to month-to-month arrangements, at over 25 receipt points. Approximately 55% percent of the gas is purchased at a percentage of an index, and the remainder is purchased at a fixed price relative to an index. We generate operating profits in the system through the margins we earn by purchasing gas from producers, then gathering, transporting and reselling the natural gas to Formosa.

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Corpus Christi System.    The Corpus Christi system is an intrastate pipeline system consisting of approximately 295 miles of gathering and transmission pipelines and extending from supply points in south Texas to markets in the Corpus Christi area. Our gathering and transmission pipelines range in diameter from four to 20 inches. We acquired the Corpus Christi system in May 2001 in conjunction with the acquisition of the Gregory gathering system and Gregory processing plant, which we collectively refer to as the CCNG Acquisition, for an aggregate purchase price of approximately $30 million. Our Corpus Christi system had average throughput of approximately 152,000 MMBtu of gas per day at the time of its acquisition. The main lines comprising the Corpus Christi system were constructed at various times from the 1940's through the 1990's.

Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 16 treating and processing plants and third party gathering systems and pipelines. The system interconnects with multiple third party pipelines through which we purchase volumes not gathered through our systems for resale and delivers natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system has a capacity of 355,950 MMBtu/d and average throughput on this system was approximately 213,800 MMBtu/d for the year ended December 31, 2003.

In June 2002, we acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows us to access new markets within Texas and to interconnect to the Florida Gas system within Texas. We have constructed an addition to this transmission line creating a connection between our Gulf Coast system and our Corpus Christi system. This connection allows us to transport gas between our two systems, thereby reducing our dependence on third-party suppliers, move gas supplies to more favorable markets and enhance our margins. In November 2002, we completed construction of the interconnect between the Hallmark Lateral and the Florida Gas system. With this connection, we began selling gas into the Florida markets and sold approximately 57,000 MMBtu/d for the year ended December 31, 2003.

We generate operating profits in our Corpus Christi system through the margins we earn by purchasing, gathering, transporting and reselling natural gas. As of December 31, 2003, we were purchasing natural gas from approximately 35 producers generally on month-to-month or short-term arrangements. For the year ended December 31, 2003, substantially all of the natural gas volumes we purchased were purchased at a fixed price relative to an index. The Corpus Christi system transports natural gas to the Corpus Christi area where our customers include multiple major refineries and other industrial installations, as well as the local electric utility. As of December 31, 2003, we were selling gas to over 20 customers primarily pursuant to contracts that expire at various times between 2003 and 2006. For the year ended December 31, 2003, all of the natural gas volumes we sold were sold at a fixed price relative to an index.

•

Gregory Gathering System.    We acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the acquisition of the Corpus Christi system. The plant

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and the gathering system are located north of Corpus Christi, Texas. The gathering system is connected to approximately 70 receipt points in San Patricio County, the Corpus Christi Bay area, Mustang Island, and adjacent coastal areas. The gathering system consists of approximately 297 miles of pipeline ranging in diameter from two inches to 18 inches with a total estimated throughput capacity of 222,000 MMBtu/d. The gathering system had average throughput of approximately 151,000 MMBtu/d for the year ended December 31, 2003 compared to an average throughput of approximately 76,500 MMBtu/d of gas per day at the time of its acquisition. The Gregory Gathering System was constructed in the 1980s.

We generate operating profits in our Gregory gathering system and our Gregory processing plant through the margins earned by purchasing, gathering, transporting and reselling natural gas, and through the incremental margin, if any, generated by processing the portion of the gas for which we retain the processing risk. As of December 31, 2003, we were purchasing gas from over 60 producers primarily pursuant to month-to-month contracts, and for the year ended December 31, 2003, approximately 95% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder was purchased at percentage of an index.

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Gregory Processing Plant.    Our Gregory processing plant is a cryogenic turbo expander with a 210,000 gallon per day fractionator that removes liquid hydrocarbons from the liquids-rich gas produced into the Gregory gathering system. Our Gregory processing plant inlet capacity was expanded from 99,900 MMBtu/d to approximately 166,500 MMBtu/d during 2003, and average throughput was approximately 106,000 MMBtu/d for the year ended December 31, 2003. At the time of acquisition, the plant was processing approximately 43,400 MMBtu/d of gas per day. The Gregory processing plant was constructed in the 1980s and expanded and upgraded in 1998 and 2003.

In addition to the margins generated by the Gregory gathering system, we generate revenues at our Gregory processing plant under two types of arrangements:

For the year ended December 31, 2003, we purchased approximately 16% of the natural gas volumes on our Gregory system under contracts in which we were exposed to the risk of loss or gain in processing the natural gas. Under these contracts, we fractionate the NGLs into separate NGL products, which we then sell at prices based upon the market price for NGL products. The processed natural gas is delivered to multiple customers at prices based on a fixed price relative to a monthly index. Since we extract Btus from the gas stream in the form of the liquids or consume it as fuel during processing, we reduce the Btu content of the natural gas but seek to more than offset this by creating value from the separated NGL products. Accordingly, our margins under these arrangements can be negatively affected in periods where the value of natural gas is high relative to the value of NGLs.

For the year ended December 31, 2003, we purchased approximately 84% of the natural gas volumes on our Gregory system at a spot or market price less a discount that includes a conditioning fee for processing and marketing the natural gas and NGLs at our Gregory processing plant with no risk of loss or gain in processing the natural gas. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas.

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Arkoma Gathering System.    We acquired the Arkoma gathering system, located in the Southeastern region of Oklahoma, in September 2000 for $10.5 million. In addition, since acquiring this system, we have acquired the Shawnee extension, consisting of 15 miles of gathering pipelines extending through additional supply areas in this region. The Arkoma gathering system when acquired was approximately 84 miles in length and included a 3,700 horsepower compressor station. With the addition of the Shawnee extension and additional well connections, the system is now approximately 100 miles in length and ranges in diameter from 2

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to 10 inches. This low-pressure system gathers gas from approximately 170 wells to three compressor stations for discharge to a mainline transmission pipeline. This system has a capacity of 21,400 MMBtu/d and average throughput was approximately 13,000 MMBtu/d for the year ended December 31, 2003.

We generate a margin for gathering and transporting gas in the Arkoma gathering system equal to a percentage of the proceeds from the sale of the natural gas to the mainline transmission pipeline into which we deliver. We take title to the gas at the point of receipt into the gathering system, with payment based upon an allocation of the metered volume sold into the mainline transmission facilities of our customer with the producer sharing their pro rata portion of the fuel costs for the compression and the removal of water from the natural gas stream.

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Mississippi Pipeline System.    We acquired the Mississippi pipeline system from DEFS in June 2003 in connection with the DEFS acquisition. The Mississippi pipeline system is located in 15 counties of south Mississippi spanning from the city of Jackson in the northwest to Hattiesburg in the southeast. The system has wellhead supply connections in most of the gas fields in the counties of operation—primarily Jasper, Jefferson Davis, Lawrence, Marion and Simpson counties. The system delivers natural gas through direct market connections to utilities and industrial end users. The pipeline system consists of approximately 638 miles of pipeline ranging in diameter from four to 20 inches with a total estimated capacity of 198,500 MMBtu/d. Average throughput on this system was approximately 79,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970s.

We generate operating profits in our Mississippi pipeline system by purchasing, gathering, transporting and reselling natural gas. We purchase gas from approximately 50 producers at the delivery points into the system and gas is sold to approximately 15 customers. The majority of contracts provide that natural gas volumes are purchased at a fixed price relative to an index.

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Seminole Gas Processing Plant.    We own an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas. The Seminole plant has dedicated long-term reserves from the Seminole San Andres unit, to which it also supplies carbon dioxide under a long-term arrangement. Revenues at the plant are derived from a fee it charges producers, including those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.59 for each Mcf of carbon dioxide returned. The plant also receives 50% of the NGLs produced by the plant. We have entered into a one-year contract with Duke Energy NGL Services, L.P. to market our NGLs on our behalf. We receive our share of proceeds from the sale of carbon dioxide from the plant operator. We are separately billed by the plant operator for our share of expenses. The plant had capacity of 150,000 Mcf/d at the time of acquisition. The recently completed expansion increased capacity by 60,000 Mcf/d, increasing total capacity to 210,000 Mcf/d. Average throughput for the plant was approximately 144,000 Mcf/d for the last six months of 2003. The plant was constructed in the 1980s.



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Conroe Gas Plant And Gathering System.    We acquired the Conroe gas plant and gathering system in June 2003 in connection with the DEFS asset acquisition. Located in Montgomery County, Texas, the Conroe gas plant is a cryogenic gas processing plant with 10 miles of gathering pipelines located within the Conroe Field Unit, which is operated by ExxonMobil. The plant gathers low pressure and high pressure natural gas through contracts with over 20 producers. The plant has outlet natural gas connections to Kinder Morgan Texas Pipeline, L.P. and Copano Field Services. Recovered NGLs are delivered into the Chaparral NGL pipeline. The plant has a capacity of 70,265 MMBtu/d and average throughput on this system was approximately 26,000 MMBtu/d for the year ended December 31, 2003. The Conroe gas plant was constructed in the 1930s.

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We generate operating profits at our Conroe gas plant from one customer primarily from compression and processing fees and from retaining 40% of the NGLs from the recycled lift gas.

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Alabama Pipeline System.    We acquired the Alabama pipeline system in June 2003 in connection with the DEFS asset acquisition. The system is located in Fayette, Lamar, Picken and Tuscaloosa Counties in west-central Alabama. The system gathers coalbed methane gas from the Black Warrior Basin and other conventional wells. The system is a series of three natural gas gathering and transmission systems consisting of approximately 125 miles of four to twelve inch pipeline with an estimated capacity of 72,300 MMBtu/d. One supplier to the system accounted for over half of the gas gathered. The gas is delivered primarily to industrial end users. Average throughput on this system was approximately 14,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970's.

We generate operating profits in our Alabama pipeline system by gathering, transporting and reselling natural gas. All gas is purchased at the delivery points into the system. The majority of the contracts are priced at a fixed basis to an area index and we sell gas to approximately five customers.

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Other Systems.    We own several small gathering systems totaling approximately 135 miles, including the Manziel system in Wood County, Texas, the San Augustine system in San Augustine County, Texas, the Freestone Rusk system in Freestone County, Texas, the Jack Starr and North Edna systems in Jackson County, Texas and the Cadeville and Aurora Centana systems in Louisiana. Through Crosstex Pipeline Partners, a limited partnership of which we are the co-general partner, we own a 28% interest in five gathering systems in east Texas, totaling 64 miles with a combined capacity of 119,000 MMBtu/d. We also own five industrial bypass systems each of which supplies natural gas directly from a pipeline to a dedicated customer. The combined volumes for these five industrial bypass systems was approximately 4,200 MMBtu/d for the year ended December 31, 2003. In addition to these systems, we own various smaller gathering and transmission systems located in Texas, New Mexico and Louisiana.

        Producer Services.    We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 50 independent producers. We engage in such activities on more than 20 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer. Profits from energy trading activities for the year ended December 31, 2003 and 2002 were $1.9 million and $2.7 million, respectively.

        Our business strategy includes developing relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business also provides us with strategic insights and valuable market intelligence which may impact our expansion and acquisition strategy.

        We offer to our customers the ability to hedge their purchase or sale price by agreeing to sell to us or to purchase from us volumes of natural gas. This risk management tool enables our customers to reduce pricing volatility associated with the sale and purchase of natural gas. When we agree to purchase or sell natural gas from a customer, we contemporaneously execute a contract for the sale or purchase of such natural gas or we enter into an offsetting obligation using futures contracts on the New York Mercantile Exchange or by using over-the-counter derivative instruments with third parties.

Treating Division

        We operate treating plants which remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications.

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Our treating division contributed approximately 22% and 27% of our gross margin in 2003 and 2002, respectively. Our treating business has grown from 35 plants in operation at December 31, 2002 to 52 plants in operation at December 31, 2003.

        As of December 31, 2003, we owned 61 treating plants, 41 of which were operated by our personnel, 11 of which were operated by producers, and 9 of which were held in inventory. We entered the treating business in 1998 with the acquisition of WRA Gas Services and we are now one of the largest gas treating operations in the Texas Gulf Coast. The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced to transportation systems to ensure that it meets pipeline quality specifications. Natural gas from certain formations in the Texas Gulf Coast, as well as other locations, is high in carbon dioxide. The majority of our active plants are treating gas from the Wilcox and Edwards formations in the Texas Gulf Coast, both of which are deeper formations that are high in carbon dioxide. Our active treating facilities include 47 amine plants and five hydrogen sulfide scavenger installations. In cases where producers pay us to operate the treating facilities, we either charge a fixed rate per Mcf of natural gas treated or charge a fixed monthly fee.

        In addition to our treating plants, we have three gathering systems with an aggregate of 43 miles of gathering pipeline located in Val Verde, Crockett, Dewitt and Live Oak counties, Texas that are connected to approximately 73 producing wells. These gathering systems are connected to three of our treating plants. The diameter of these gathering pipelines ranges from two to six inches. These gathering assets in the aggregate have a capacity of 61,000 MMBtu/d and average throughput was approximately 20,800 MMBtu/d for the year ended December 31, 2003. In cases where we both gather and treat natural gas, our fee is generally based on throughput.

        A component of our strategy is to purchase used plants and then refurbish and repair them at our shop and seven-acre yard in Victoria, Texas and our 14-acre yard in Odessa, Texas. We believe that we can purchase used plants and recondition them at a significant cost savings to purchasing new plants. We have an inventory of plants of varying sizes which can be deployed after refurbishment. We also mount most of the plant equipment on skids allowing them to be moved in a timely and cost efficient manner. At such time as our active plants come offline, the Partnership will put them in our inventory pending redeployment. We believe our plant inventory gives us an advantage of several weeks in the time required to respond to a producer's request for treating services.

        Treating process.    The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb the impurities from the gas. After mixing, gas and amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute. The size range of the 52 plants in operation is 3.5 to 300 gallons per minute, and the size range of the 9 plants in inventory is 3.5 to 1,000 gallons per minute.

        Hydrogen sulfide scavenger facilities use a liquid or solid chemical that reacts with hydrogen sulfide thereby removing it from the gas. Used chemicals are disposed of and cannot be regenerated as amine can. The facilities are primarily vertical towers mounted on concrete foundations. As of December 31, 2003, we had two such facilities which were operated by the producer.

Industry Overview

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

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        The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use 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 begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. 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.

        Natural gas treating.    Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide. Treating plants are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems to ensure that it meets pipeline quality specifications.

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

        Natural gas transmission.    Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, plant tailgates, and gathering systems and deliver it to industrial end-users, utilities and to other pipelines. All of our transmission pipelines are intrastate systems.

Risk Management

        As we purchase natural gas, we establish a margin by selling natural gas for physical delivery to third party users, using over-the-counter derivative instruments or by entering into a future delivery

11

obligation under futures contracts on the New York Mercantile Exchange. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes.

Competition

        The business of providing natural gas gathering, transmission, treating, processing and marketing services is highly competitive. We face strong competition in acquiring new natural gas supplies. Our competitors in obtaining additional gas supplies and in treating new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. The main difference between us and our competitors is that we offer most midstream services, while our competitors typically offer only a few select services. Many of our competitors have substantially greater capital resources and control substantially greater supplies of natural gas. Our major competitors in the Texas Gulf Coast area for natural gas supplies and markets include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services. Our major competitors in Mississippi for natural gas supplies and markets include Southern Natural Gas and Gulf South Pipeline Company.

        Our gas treating operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant and operations similar to ours. We also face competition from vendors of used equipment that occasionally operate plants for producers. Our primary competitor for natural gas treating services in our principal market area is The Hanover Company.

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

Natural Gas Supply

        Our end-user pipelines have connections with major interstate and intrastate pipelines, which we believe have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of our gathering systems, we evaluated well and reservoir data furnished by producers to determine the availability of natural gas supply for the systems. Based on those evaluations, we believe that there should be adequate natural gas supply to recoup our investment with an adequate rate of return. We do not routinely obtain independent evaluations of reserves dedicated to our systems due to the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

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

        During the year ended December 31, 2003, we had one customer that individually accounted for more than 10% of consolidated revenues. During the year ended December 31, 2003, Kinder Morgan Tejas accounted for 20.5% of our consolidated revenue. While this customer represents a significant

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percentage of consolidated revenues, the loss of this customer would not have a material impact on our results of operations.

Regulation

        Regulation by FERC of Interstate Natural Gas Pipelines.    Under the Natural Gas Act ("NGA"), the Federal Energy Regulatory Commission ("FERC") generally regulates the transportation of natural gas in interstate commerce. We do not own any interstate natural gas pipelines, so the FERC does not directly regulate any of our facilities or operations. However, as discussed below, we do perform some interstate transmission service that is incidental to our intrastate business, and this interstate transmission is subject to FERC rate regulation. Also, FERC's regulation of interstate transportation by others indirectly influences certain aspects of our business and the market for our products. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines' rates and rules and policies that may affect rights of access to natural gas transportation capacity.

        Intrastate Pipeline Regulation.    Our intrastate natural gas pipeline operations are not subject to regulation by FERC, but they are subject to regulation by various agencies of the states in which they are located, principally the Texas Railroad Commission, or TRRC. However, to the extent that our intrastate pipeline systems provide incidental transportation of natural gas in interstate commerce, the rates, terms and conditions of such transportation services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act ("NGPA"). Section 311 applies to, among other things, the providing of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. 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.

        Our operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates.

        A twelve-mile section of our Mississippi gathering system is regulated by the Mississippi Oil and Gas Board as it transports gas not owned by us for a fee. Our one hundred twenty-five mile gathering system in Oklahoma is not regulated by the Oklahoma Corporation Commission. Similarly, gathering systems we own in Alabama and Louisiana are not subject to regulation by the Alabama State Oil and Gas Board and the Louisiana Office of Conservation respectively. While it is possible that Alabama, Louisiana, Oklahoma, Mississippi and New Mexico may try to assert or expand jurisdiction on those lines, it is not likely that the assertion or expansion of that jurisdiction would have a significant effect on our operations in those states because all tend to apply Federal regulations to natural gas pipeline facilities without numerous additional state-specific requirements.

        Gathering Pipeline Regulation.    Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities, for purposes of rate regulation to the extent we

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provide NGPA Section 311 services over such facilities, are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.

        We are subject to state ratable take and common purchaser 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. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

        Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        Sales of Natural Gas.    The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect less extensive regulation. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations, and we note that some of FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Environmental Matters

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

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        Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays. While we believe that we currently hold material governmental approvals required to operate our major facilities, we are currently evaluating and updating permits for certain of our facilities that primarily were obtained in recent acquisitions. As part of the regular overall evaluation of our operations, we have implemented procedures to and are presently working to ensure that all governmental approvals, for both recently acquired facilities and existing operations are updated, as may be necessary. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our operating results or financial condition.

        The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our possible future operations, and we cannot assure you that we will not incur significant costs and liabilities including those relating to claims for damage to property and persons as a result of such upsets, releases, or spills. In the event of future increases in costs, we may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to property. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and in order to minimize the costs of such compliance.

        Hazardous Substance and Waste.    To a large extent, the environmental laws and regulations affecting our possible future operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions 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. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances 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 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 future, ordinary operations, we may generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous state laws.

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

        We currently own or lease, and have in the past owned or leased, and in the future we may own or lease, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination.

        We recently acquired two assets from DEFS that have environmental contamination, including a gas plant in Montgomery County, near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under our purchase agreement, Duke has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, the remediation costs associated with the Conroe site will be covered by agreements with TRC Companies and AIG. Therefore, we do not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.

        Air Emissions.    Our operations are, and our possible future operations will likely be, subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our processing and fractionating plants, pipelines, and storage facilities or any of our future assets that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. Such requirements, if applicable to our operations, could cause us to incur capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission related issues. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of the our facilities and which may apply to some of our possible future facilities. 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

16

emission sources. Although we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or operating results.

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

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

        Endangered Species Act.    The Endangered Species Act restricts activities that may affect endangered species or their habitats. Presently, we operate in only one area that is designated as a critical habitat for a certain species of beetle. This area consists of 29 counties in eastern and central Oklahoma into which part of our gathering system extends. A coalition of oil and gas industry and regulatory agencies are currently working together to minimize impacts on future construction and operation activities for oil and gas production and transportation. This designated area has had no material effect on our operations in Oklahoma to date. While we have no reason to believe that we operate in any other area that is currently designed as habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

        Safety Regulations.    Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, and the Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004 relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines and segments of gathering lines in certain populated areas 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. We believe that our pipeline operations are in substantial compliance with applicable HLPSA 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

17

compliance with the HLPSA or PIM requirements will not have a material adverse effect on our results of operations or financial positions.

Office Facilities

        In addition to our gathering and treating facilities discussed above, we occupy approximately 21,000 square feet, increasing up to approximately 40,000 square feet over the next two years, of space at our executive offices in Dallas, Texas under a lease expiring in March 2010.

Employees

        As of December 31, 2003, our operating partnership, Crosstex Energy Services, L.P., had approximately 189 full-time employees. Approximately half of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.

Item 2. Properties

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

Title to Properties

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

        We believe that we have satisfactory title to all of our assets. Title to property may be subject to encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

Item 3. Legal Proceedings

        We are not currently a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverage and deductibles as the managing 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.

Item 4. Submission of Matters to a Vote of Security Holders

        No matters were submitted to security holders during the fourth quarter of the year ended December 31, 2003.

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PART II

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

        The Partnership's common units representing limited partner interests in the Partnership are listed on the NASDAQ National Market under the symbol "XTEX". Common units began trading on December 12, 2002, at an initial public offering price of $20.00 per common unit. On March 3, 2004, the market price for the common units was $51.85 per unit and there were approximately 5,195 record holders and beneficial owners (held in street name) of the Partnership's common units and one record holder of the Partnership's subordinated units. There is no established public trading market for the Partnership's subordinated units.

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

(a)

The distribution for the quarter ended December 31, 2003 and was paid on Febrruary 13, 2004.

(b)

Reflects minimum quarterly distribution of $0.50 for the quarter ended March 31, 2003 and the pro rata portion of the $0.50 minimum quarterly distribution, covering the period for December 17, 2002 closing of the initial public offering through December 31, 2002.

        Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. During the subordination period (as described below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:

•

provide for the proper conduct of our business;



•

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



•

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

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

        Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our

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agreements or obligations. Our distributions are effectively made 98 percent to unitholders and two percent to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 15 percent, 25 percent and 50 percent based on incremental distribution thresholds as set forth in our partnership agreement.

        Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default is existing, under our credit facility. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Indebtedness."

        During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

        The subordination period will extend until the first day of any quarter beginning after December 31, 2007 in which each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;



•

the "adjusted operating surplus" as defined in the partnership agreement generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and



•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will participate pro rata with the other common units in distributions of available cash.

Item 6. Selected Financial Data

        The following table sets forth selected historical financial and operating data of Crosstex Energy, L.P. and our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, L.P. or our predecessor, Crosstex Energy Services, Ltd. The investment in our predecessor by Yorktown Energy Partners IV, L.P. in May 2000 resulted in the dissolution of the predecessor partnership and the creation of a new partnership with the same organization, purpose, assets, and liabilities. Accordingly, the financial statements of our predecessor for 2000 are divided into the four months ended April 30, 2000 and the eight months ended December 31, 2000 because a new basis of accounting was established effective May 1, 2000 to give effect to the Yorktown transaction. In addition, the summary historical financial and operating data of Crosstex Energy Services, Ltd. include the results of operations of the Arkoma system beginning in September 2000, the Gulf Coast system beginning in September 2000, the CCNG system, which includes the Corpus Christi system, the

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Gregory gathering system and the Gregory processing plant, beginning in May 2001, the Vanderbilt system beginning in December 2002 and the DEFS assets beginning in June 2003.

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

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(1)

Crosstex Energy Services, Ltd. is the predecessor to Crosstex Energy, L.P. Results of operations and balance sheet data prior to May 1, 2000 represent historical results of the predecessor to Crosstex Energy Services, Ltd. These results are not necessarily comparable to the results of Crosstex Energy Services, Ltd. subsequent to May 2000 due to the new basis of accounting.

(2)

For the year ended December 31, 2003, the amount for which general partner is entitled to reimbursement from us for allocated general and administrative expenses is limited to $6.0 million. Such limitation does not apply to expenses incurred in connection with acquisitions or business development opportunities evaluated on our behalf.

(3)

Net income (loss) per limited partner unit is not applicable for periods prior to our initial public offering. Net income per unit of $0.04 for the year ended December 31, 2002 represents allocation of our 2002 net income for the period from December 17, 2002 to December 31, 2002.

(4)

2003 distributions include fourth quarter of 2003 distributions of $0.75 per unit paid in February 2004 and 2002 distributions include fourth quarter of 2002 distributions of $0.056 per unit paid in February 2003.

(5)

Gross margin is defined as revenue less related cost of purchased gas.

(6)

Represent volumes for treating plants operated by us whereby we receive a fee based on the volumes treated.

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

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

Overview

        We are a Delaware limited partnership formed by Crosstex Energy, Inc. on July 12, 2002 to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the year ended December 31, 2003, 78% of our gross margin was generated in the Midstream division, with the balance in the Treating division, and approximately 71% of our gross margin was generated in the Texas Gulf Coast region. We focus on gross margin to manage our business because our business is generally to gather, process, transport, market or treat gas for a fee or a buy-sell margin. We buy and sell most of our gas at a fixed relationship to the relevant index price so our margins are not significantly affected by changes in gas prices. As explained under "Commodity

22

Price Risk" below, we enter into financial instruments to reduce volatility in our gross margin due to price fluctuations.

        Since the formation of our predecessor, we have grown significantly as a result of our construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2000 through December 31, 2003, we have invested approximately $222.0 million to develop or acquire new assets. The purchased assets were acquired from numerous sellers at different periods and were accounted for under the purchase method of accounting. Accordingly, the results of operations for such acquisitions are included in our financial statements only from the applicable date of the acquisition. As a consequence, the historical results of operations for the periods presented may not be comparable.

        Our results of operations are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities or treated at our treating plants as well as fees earned from recovering carbon dioxide and natural gas liquids at a non-operated processing plant. We generate revenues from five primary sources:

•

gathering and transporting natural gas on the pipeline systems we own;



•

processing natural gas at our processing plants;



•

treating natural gas at our treating plants;



•

recovering carbon dioxide and natural gas liquids at a non-operated processing plant; and



•

providing producer services.

        The bulk of our operating profits are derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See "Commodity Price Risk" below for a discussion of how we manage our business to reduce the impact of price volatility.

        We generate producer services revenues through the purchase and resale of natural gas. We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 50 independent producers. We engage in such activities on more than 20 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.

        We generate treating revenues under three arrangements:

•

a volumetric fee based on the amount of gas treated, which accounted for approximately 55% and 66% of the operating income in our Treating division for the years ended December 31, 2003 and 2002, respectively;



•

a fixed fee for operating the plant for a certain period, which accounted for approximately 38% and 22% of the operating income in our Treating division for the years ended December 31, 2003 and 2002, respectively; or

23

•

a fee arrangement in which the producer operates the plant, which accounted for approximately 7% and 12% of the operating income in our Treating division for the years ended December 31, 2003 and 2002, respectively.

        Typically, we incur minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through our pipeline assets. Therefore, we recognize a substantial portion of incremental gathering and transportation revenues as operating income.

        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 and associated transportation and communication costs, 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.

        Our general and administrative expenses are dictated by the terms of our partnership agreement and our omnibus agreement with Crosstex Energy, Inc. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the 12 month period ended in December 2003, the amount which we reimbursed our general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf could not exceed $6.0 million. This reimbursement cap did not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on our behalf. This cap expired in December 2003.

        Crosstex Energy, Inc. modified certain terms of certain outstanding options in the first quarter of 2003 which allowed the option holders to elect to be paid in cash for the modified options based on the fair value of the options. These modifications resulted in variable award accounting for the modified options until the option holders elect to cash out the options or the election to cash out the options lapses. CEI is responsible for paying the intrinsic value of the options for the holders who elect to cash out their options. December 31, 2003 was the last valuation date that a holder of modified options could elect the cash-out alternative. Accordingly, effective January 1, 2004, the remaining modified options will be accounted for as fixed options. We recognized total compensation expense of approximately $5.0 million related to these modified options, which has been recorded by the Partnership as non-cash stock based compensation expense in the year ended December 31, 2003.

        We have grown significantly through asset purchases in recent years, which creates many of the major differences when comparing operating results from one period to another. The most significant asset purchases are the acquisitions of our CCNG system, Vanderbilt system and DEFS assets.

        We acquired the CCNG system in May 2001 for a purchase price of approximately $30.0 million. The CCNG system included four principal assets: the Corpus Christi system, the Gregory gathering system, the Gregory processing plant and the Rosita treating plant.

•

The Corpus Christi system consists of approximately 295 miles of gathering and transmission lines extending from supply points in south Texas to markets in Corpus Christi Texas, with average throughput of approximately 152,000 MMBtu of gas per day at the time of the acquisition.

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•

The Gregory gathering system consists of approximately 297 miles of gathering lines located primarily in the Corpus Christi Bay area, with average throughput of approximately 76,500 MMBtu of gas per day at the time of the acquisition.



•

The Gregory processing plant processes most of the gas gathered by the Gregory gathering system, extracting the liquids, fractionating them into NGLs, and selling the remaining residue gas. At the time of the acquisition, the plant was processing approximately 43,400 MMBtu of gas per day.



•

The Rosita treating plant was treating approximately 25,000 MMBtu of gas per day at the time of its acquisition. The Rosita treating plant is operated in the Partnership's Treating Division, whereas all of the other assets in the CCNG acquisition are included in the Partnership's Midstream Division.

        We acquired the Vanderbilt system in December 2002 for a purchase price of $12.0 million. The Vanderbilt system consists of approximately 200 miles of gathering lines in the same approximate geographic area as the Gulf Coast System. At the time of its acquisition, it was transporting approximately 32,000 MMBtu of gas per day.

        We acquired the DEFS assets in June 2003 for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. The acquisition provided us with a new core area for growth in south central Mississippi, expanded our presence in West Texas, increased the total miles of our pipelines from 1,700 to 2,500 and enabled us to enter the business of carbon dioxide separation.

Commodity Price Risk

        Our profitability has been and will continue to be affected by volatility in prevailing NGL product and natural gas prices. Changes in the prices of NGL products correlate closely with changes in the price of crude oil. NGL product and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.

        Profitability under our gas processing contracts is impacted by the margin between NGL sales prices and the cost of natural gas and may be negatively affected by decreases in NGL prices or increases in natural gas prices.

        Changes in natural gas prices impact our profitability since the purchase price of a portion of the gas we buy (approximately 8.4% in 2003) is based on a percentage of a particular natural gas price index for a period, while the gas is resold at a fixed dollar relationship to the same index. Therefore, during periods of low gas prices, these contracts can be less profitable than during periods of higher gas prices. However, on most of the gas we buy and sell, margins are not affected by such changes because the gas is bought and sold at a fixed relationship to the relevant index. Therefore, while changes in the price of gas can have very large impacts on revenues and cost of revenues, the changes are equal and offsetting.

        Set forth in the table below is the volume of the natural gas purchased and sold at a fixed discount or premium to the index price and at a percentage discount or premium to the index price for our principal gathering and transmission systems and for our producer services business for the year ended

25

December 31, 2003. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas.

(1)

Gas sold is less than gas purchased due to production of natural gas liquids.

(2)

These volumes are not reflected in revenues or purchased gas cost, but are presented net as a component of profit (loss) on energy trading activities.

        We estimate that, due to the gas that we purchase at a percentage of index price, for each $0.50 per MMBtu increase or decrease in the price of natural gas, our gross margins increase or decrease by approximately $0.7 million on an annual basis (before consideration of the hedges discussed below). As of December 31, 2003, we have hedged a portion of our exposure to such fluctuations in natural gas prices as follows for future periods:

        We expect to continue to hedge our exposure to gas production which we purchase at a percentage of index when market opportunities appear attractive.

        In addition to the margins generated by the Gregory gathering system, we generate revenues at our Gregory processing plant under two types of arrangements:

•

For the year ended December 31, 2003, we purchased approximately 16% the natural gas volumes on our Gregory system under contracts in which we were exposed to the risk of loss or gain in processing the natural gas. Under these contracts, we fractionate the NGLs into separate NGL products, which we then sell at prices based upon the market price for NGL products. All of the processed natural gas, up to 100,000 MMcf/d, is delivered to two customers at a price based on a fixed price relative to a monthly index. Since we extract Btu's from the gas stream in the form of the liquids or consume it as fuel during processing, we reduce the Btu content of the natural gas but seek to more than offset this by creating value from the separated NGL products. Accordingly, our margins under these arrangements can be negatively affected in periods where the value of natural gas is high relative to the value of NGLs.



•

For the year ended December 31, 2003, we purchased approximately 84% of the natural gas volumes on our Gregory system at a spot or market price less a discount that includes a fixed

26

margin for gathering, processing and marketing the natural gas and NGLs at our Gregory processing plant with no risk of loss or gain in processing the natural gas. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas. We anticipate purchasing increasing percentages of gas under fixed fee arrangements as opposed to contracts under which the processing economics are for our account.

        Our Conroe gas plant and gathering system generates revenues based on fees it charges to producers for gathering and compression services, and we retain 40% of the NGLs produced from a portion of the gas processed at the facility.

        We own an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas. The Seminole plant has dedicated long-term reserves from the Seminole San Andres unit, to which it also supplies carbon dioxide under a long-term arrangement. Revenues at the plant are derived from a fee it charges producers, including those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.59 for each Mcf of carbon dioxide returned. Reinjected carbon dioxide is used in a tertiary oil recovery process in the field. The plant also receives 50% of the NGLs produced by the plant. Therefore, we have commodity price exposure due to variances in the prices of NGLs. In the last half of 2003, our share of NGLs totaled 2,824,000 gallons at an average price of $0.5154 per gallon. We have entered into a one-year contract with Duke Energy NGL Services, L.P. to market our NGLs on our behalf, and receive our share of proceeds from the sale of carbon dioxide from the plant operator. We are separately billed by the plant operator for our share of expenses.

        Gas prices can also affect our profitability indirectly by influencing drilling activity and related opportunities for gas gathering, treating and processing.

Results of Operations

        Set forth in the table below is certain financial and operating data for the Midstream and Treating divisions for the periods indicated.

27

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

        Gross Margin.    Midstream gross margin was $46.7 million for the year ended December 31, 2003 compared to $23.7 million for the year ended December 31, 2002, an increase of $23.0 million, or 97%. The largest increase in gross margin was due to the acquisition of assets from Duke Energy Field Services on June 30, 2003. These assets added gross margin of $9.4 million. The CCNG system had significant growth due to an increase in on-system volume and the addition of the Hallmark lateral, resulting in an increase in margin of $4.7 million. We acquired the Vanderbilt Gathering system on December 31, 2002; this system added gross margin of $4.4 million. Gregory gathering system and Gregory processing plant had increased margin of $2.6 million. These systems had significant growth in volume due to producer drilling activity in the area, to which we responded with the Gregory plant expansion during 2003. The Gulf Coast system had increased margin of $1.2 million despite the fact that volumes declined. The reason for the decline in volume was because we sourced two markets from Vanderbilt the last half of 2003 that were previously sourced from the Gulf Coast system. We had an increase in volume and increase in margin due to a large customer taking gas from our system for 12 months in 2003 and only 6 months in 2002, and we had increased margin due to renegotiation of producer contracts. The Arkoma system also had increased volume, creating an increase in margin of $0.8 million.

        Treating gross margin was $13.0 million for the year ended December 31, 2003 compared to $9.0 million in the same period in 2002, an increase of $4.0 million, or 44%. The increase was due to 27 new plants placed in service in 2003, which generated $3.7 million offset by 10 plants removed from service in 2003, which decreased margin by $0.8 million (a net increase of $2.9 million). In addition, an increase in volume at two plants with throughput-based contracts accounted for $1.1 million of the increase in treating margin.

        Operating Expenses.    Operating expenses were $17.7 million for the year ended December 31, 2003, compared to $11.4 million for the year ended December 31, 2002, an increase of $6.3 million, or 55%. An increase of $3.1 million was associated with the acquisition of assets from Duke Energy Field Services in June 2003. Costs for our technical services support increased by approximately $0.8 million due to staff additions to operate the assets acquired in December 2002 and in June 2003 from DEFS and to manage other construction projects. The Vanderbilt system added $1.1 million to operating expenses, new treating plants increased operating expenses by $0.6 million and the Gregory Plant expansion added $0.4 million in operating expenses.

        General and Administrative Expenses.    General and administrative expenses were $6.8 million for the year ended December 31, 2003 compared to $7.5 million for the year ended December 31, 2002, a decrease of $0.7 million, or 9%. The decrease was due to the general and administrative expense limit set by our partnership agreement for the year of 2003, which resulted in general and administrative expenses in excess of specified levels being reimbursed by the general partner. Had the cap not been in place, general and administrative expenses would have been $10.2 million, or an increase of $2.7 million. The increase was primarily due to increases in staffing associated with the requirements of the Duke Energy Field Services acquisition and associated with being a public entity.

        Impairments.    We had no impairment expense in 2003 compared to $4.2 million in 2002. See "Year Ended December 31, 2002 Compared to Year Ended December 31, 2001" for a discussion of the 2002 charge.

        (Profit) Loss on Energy Trading Activities.    The profit on energy trading activities was $1.9 million for the year ended December 31, 2003 compared to $2.7 million for the year ended December 31, 2002, a decrease of $0.8 million, or 30%. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $2.2 million in 2003 and $1.8 million in 2002, an increase of $0.4 million, or 22%. This increase is primarily due to an increase in our producer services volumes. In addition, losses of $0.3 million and gains of $0.9 million relating

28

primarily to options bought and/or sold in the management of the company's Enron position were booked in 2003 and 2002, respectively.

        Depreciation and Amortization.    Depreciation and amortization expenses were $13.3 million for the year ended December 31, 2003 compared to $7.7 million for the year ended December 31, 2002, an increase of $5.5 million, or 71%. The increase related to the Duke assets purchased in June 2003 was $2.3 million. The Vanderbilt system, purchased in December 2002 added $1.0 million of depreciation, new treating plants placed in service in 2003 resulted in an increase of $0.9 million and the Hallmark system added $0.3 million. The remaining $1.0 million increase in depreciation and amortization is a result of expansion projects and other new assets, such as the expansion of the Gregory Plant.

        Interest Expense.    Interest expense was $3.4 million for the year ended December 31, 2003 compared to $2.7 million for the year ended December 31, 2002, an increase of $0.7 million, or 25%. The increase relates primarily to bank debt incurred in the acquisition of the Duke assets in June, 2003 and by higher interest rates (weighted average rate of 5.35% in 2003 compared to 4.67% in 2002).

        Net Income (Loss).    Net income for the year ended December 31, 2003 was $15.2 million compared to $2.0 million for the year ended December 31, 2002, an increase of $13.2 million. This was generally the result of the increase in gross margin of $26.9 million from 2002 to 2003, offset by increases in ongoing cash costs for operating expenses and interest expense as discussed above. Non-cash charges for depreciation and amortization expenses and stock based compensation also increased.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

        Gross Margin.    Midstream gross margin was $23.7 million for the year ended December 31, 2002 compared to $17.9 million for the year ended December 31, 2001, an increase of $5.8 million, or 32%. The Corpus Christi system, the Gregory gathering system and the Gregory processing plant were acquired in May 2001. The gross margin from these assets for the 12-month period of 2002 exceeded that of the 8-month period in 2001 by $6.9 million. This was offset by lower margin of $0.8 million at the Arkoma system and $0.4 at the Gulf Coast system due to lower prices in 2002.

        Treating gross margin was $9.0 million for the year ended December 31, 2002 compared to $6.3 million for the same period in 2001, an increase of $2.7 million, or 43%. The increase was primarily due to 14 new plants placed in service in 2002, which generated $1.6 million. In addition, margin of $1.0 million was generated at two plants due to increased volume and additional margin of $0.9 million from six plants in service the entire year 2002, but were in operation only a few months in 2001. This was offset by $0.3 million decrease in margin from four plants being removed from service and another $0.3 million from contract restructuring at one treating facility.

        Operating Expenses.    Operating expenses were $11.4 million for the year ended December 31, 2002, compared to $7.8 million for the year ended December 31, 2001, an increase of $3.0 million, or 47%. $1.8 million of the increase was associated with the CCNG assets purchased in May 2001 and another $1.0 million was associated with growth in the treating division.

        General and Administrative Expenses.    General and administrative expenses were $7.5 million for the year ended December 31, 2002 compared to $5.6 million for the year ended December 31, 2001, an increase of $1.9 million, or 35%. The increases were associated with increases in staffing associated with the requirements of the CCNG assets and in preparation for our initial public offering.

        Impairments.    Impairment expense was $4.2 million in 2002 compared to $2.9 million in 2001. Intangible assets were booked associated with the contract values of certain treating plants and other assets in conjunction with the Yorktown investment in May, 2000. Impairment charges in 2002 and 2001 are associated with writing off certain of these intangible contract values. The charges in 2001 relate to intangible contract values associated with the Jonesville processing plant, which was transferred out of

29

the partnership in conjunction with the initial public offering. Impairment charges in 2002 are primarily associated with intangible contract values at 4 specific treating plants. Two of the plants are still working at the location where they were sited at the time of the Yorktown investment, but had experienced recent declines in cash flows. As the operator of the wells behind these plants had recently told the company that it was canceling its drilling plans in the area, the declines are expected to continue until the plants are relocated. The other two treating plants were removed from service during 2002 at the locations where they were sited at the time of the Yorktown investment, and therefore the intangible contract values associated with that particular location were deemed impaired. (One of the plants was immediately contracted at another location at a higher rental rate than previously in effect. The other plant is currently in inventory.)

        (Profit) Loss on Energy Trading Activities.    The profit on energy trading activities was $2.7 million for the year ended December 31, 2002 compared to a loss of $3.7 million for the year ended December 31, 2001, an increase of $6.4 million. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $1.8 million in 2002 and $1.9 million in 2001. In addition, gains of $0.9 million relating primarily to options bought and/or sold in the management of the company's Enron position were booked in 2002. Offsetting the gains from the producer services off-system gas marketing operations in 2001 was the $5.7 million reserve booked against the company's Enron receivable due to Enron Corporation's December 2001 bankruptcy.

        Depreciation and Amortization.    Depreciation and amortization expenses were $7.7 million for the year ended December 31, 2002 compared to $6.1 million for the year ended December 31, 2001, an increase of $1.6 million, or 27%. The increase is primarily related to additional depreciation expense associated with the CCNG assets purchased in May 2001, partially offset by a decrease in amortization expense due to goodwill no longer being amortized in 2002 in accordance with SFAS 142.

        Interest Expense.    Interest expense was $2.7 million for the year ended December 31, 2002 compared to $2.3 million for the year ended December31, 2001, an increase of $.4 million, or 21%. The increase relates primarily to bank debt incurred in the acquisitions of the CCNG assets in May, 2001, offset by lower interest rates.

        Net Income (Loss).    Net income (loss) for the year ended December 31, 2002 was $2.0 million compared to ($3.9) million for the year ended December 31, 2001, an increase of $5.9 million. Gross margin increased by $8.6 million from 2001 to 2002, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, and interest expense as discussed above. Non-cash charges for depreciation and amortization expenses and for impairment expense also increased, offset by the gain on energy trading activities.

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. For further details on our accounting policies and a discussion of new accounting pronouncements. See Note 2 of the Notes to Combined Financial Statements.

        Revenue Recognition and Commodity Risk Management.    We recognize revenue for sales or services at the time the natural gas or natural gas liquids are delivered or at the time the service is performed.

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        We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and natural gas liquids. We also manage our 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 our future commitments and significantly reduce our risk to the movement in natural gas prices.

        Prior to January 1, 2001, financial instruments which qualified for hedge accounting were accounted for using the deferral method of accounting, whereby unrealized gains and losses were generally not recognized until the physical delivery required by the contracts was made.

        Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. In accordance with SFAS No. 133, 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.

        We conduct "off-system" gas marketing operations as a service to producers on systems that we do not own. We refer to these activities as part of producer services. In some cases, we earn an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, we purchase the natural gas from the producer and enter into a sales contract with another party to sell the natural gas. Where we take title to the natural gas, the purchase contract is recorded as cost of gas purchased and the sales contract is recorded as revenue upon delivery.

        We manage our price risk related to future physical purchase or sale commitments for producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. Prior to October 26, 2002, we accounted for our producer services natural gas marketing activities as energy trading contracts in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 required energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. In October 2002, the EITF reached a consensus to rescind EITF No. 98-10. Accordingly, energy trading contracts entered into subsequent to October 25, 2002, should be accounted for under accrual-basis accounting rather than mark-to-market accounting unless the contracts meet the requirements of a derivative under SFAS No. 133. Our energy trading contracts qualify as derivatives, and accordingly, we continue to use mark-to-market accounting for both physical and financial contracts of our producer services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

        For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period in addition to the realized gains or losses on settled activities are reported as profit or loss on energy trading activities in the statements of operations.

        Impairment of Long-Lived Assets.    In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate 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

31

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 our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our 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;



•

our 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 our cash flows, which could require us to record an impairment of an asset.

Liquidity and Capital Resources

        Cash Flows.    Net cash provided by operating activities was $46.5 million for the year ended December 31, 2003 compared to cash used by operations of $5.7 million for the year ended December 31, 2002. Income before non-cash income and expenses was $33.6 million in 2003 and $14.0 million in 2002. Changes in working capital provided $12.8 million in cash flows from operating activities in 2003 and used $19.7 million in cash flows from operating activities in 2002. Income before non-cash income and expenses increased between years primarily due to asset acquisitions as discussed in "Results of Operations—Year Ended December 31, 2003 compared to year ended December 31, 2002." Changes in working capital provided $12.8 million in cash flows in 2003 primarily due to $3.5 million in prepayments by certain customers in December 2003 combined with $3.8 million due to delays in collecting from a few large customers in December 2002 until January 2003. In addition, property cost accruals increased by approximately $1.5 million due to an increase in capital projects late in 2003 as compared to 2002. The remaining changes in working capital were due to timing of receipts and disbursements in the ordinary course of business.

        Net cash used in investing activities was $110.3 million and $33.2 million for the year ended December 31, 2003 and 2002, respectively. Net cash used in investing activities during 2003 related to the Duke acquisition ($68.1 million) as well as internal growth projects, and during 2002 primarily related to internal growth projects and the acquisitions of the Vanderbilt system ($12.0 million) and the Hallmark Lateral ($2.3 million). The primary internal growth projects referred to during 2003 were the Gregory plant expansion ($7.4 million), improvements to the Vanderbilt system ($4.7 million), and buying, refurbishing and installing treating plants ($9.9 million). The main projects in the 2002 period were the connection of the Hallmark system ($4.3 million), the Calpine interconnect ($1.1 million), buying, refurbishing and installing treating plants ($7.3 million), and a line extension at the Gregory plant ($0.9 million).

        Net cash provided by (used in) financing activities was $62.7 million and $39.9 million for the years ended December 31, 2003 and 2002, respectively. Financing activities in 2003 relate principally to the funding of the Duke assets acquisition and internal growth projects discussed above from bank

32

borrowings and proceeds from the sale of common units discussed below. Financing activities during 2002 primarily represented funding or refunding of the partnership's debt and working capital needs through bank borrowings and net proceeds from our initial public offering in December 2002 and partner contributions. Financing activities also included a decrease in drafts payable of $17.1 million for the year ended December 31, 2003 and an increase in drafts payable of $25.6 million for the year ended December 31, 2002. In order to reduce our interest costs, we borrow money to fund outstanding checks as they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility.

        Off-Balance Sheet Arrangements.    We had no off-balance sheet arrangements as of December 31, 2003 and 2002.

        September 2003 Sale of Common Units.    In September 2003, we completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. We received net proceeds of approximately $59.1 million, including an approximate $1.3 million capital contribution by our general partner. The net proceeds were used to repay borrowings outstanding under the bank credit facility of our operating partnership.

        Capital Requirements.    The natural gas gathering, transmission, treating and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

•

maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain existing operating capacity of our assets and to extend their useful lives, or other capital expenditures which do not increase the partnership's cash flows; and



•

growth capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems, transmission capacity, processing plants or treating plants, and to construct or acquire new pipelines, processing plants or treating plants.

        Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider a variety of assets for potential acquisitions.

        We believe that cash generated from operations will be sufficient to meet our present quarterly distribution level of $0.75 per quarter and to fund a portion of our anticipated capital expenditures through December 31, 2004. We expect to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below. Total capital expenditures are budgeted to be approximately $17 million in 2004. Our ability to pay distributions to our unit holders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

        Subsequent Event.    We entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power for $76.2 million. The acquisition will increase our pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. We will finance the acquisition through borrowings under our existing bank credit facility, issuance of additional senior notes or other financing alternatives.

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        Total Contractual Cash Obligations.    A summary of our total contractual cash obligations as of December 31, 2003, is as follows:

        The above table does not include any physical or financial contract purchase commitments for natural gas.

        Other Obligations.    We receive notices from various pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. Since we balance our purchases and sales in the pipelines, these allocation corrections normally have little impact to our gross margin since both the purchase and sale on the pipeline system require corrections. At December 31, 2003, we had a dispute related to one such allocation correction with a pipeline company and a customer on that pipeline. In reallocating previous settled deliveries, the pipeline company has billed us for approximately $1.2 million of gas deliveries, which occurred in the period from December 2000 through February 2001. We have, in turn, billed our customer who was over paid due to the allocation error. Our customer is disputing the timeliness of this corrected billing. The allocation error occurred prior to the acquisition by us of the subsidiary involved in the dispute. We have an indemnity from the seller for liabilities prior to the acquisition date. As of December 31, 2003, we have recorded a receivable of $1.2 million in other current receivables and a liability of $1.2 million in other current liabilities related to this allocation correction. We believe the dispute of the receivable by our customer is without merit, and further believe that we are protected against loss by our potential indemnity claim

Description of Indebtedness

        Bank Credit Facility.    In June 2003 our operating partnership, Crosstex Energy Services, L.P., entered into a $100 million senior secured credit facility with Union Bank of California, N.A. (as a lender and as administrative agent) and other lenders which was increased to $120 million in October 2003, consisting of the following two facilities:

•

a $70.0 million senior secured revolving acquisition facility; and



•

a $50.0 million senior secured revolving working capital and letter of credit facility.

        The acquisition facility was used for the DEFS acquisition and will be used to finance the acquisition and development of gas gathering, treating and processing facilities, as well as general partnership purposes. At December 31, 2003, $20.0 million was outstanding under the acquisition facility, leaving approximately $50.0 available for future borrowings. The acquisition facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the acquisition credit facility may be re-borrowed.

        The working capital and letter of credit facility will be used for ongoing working capital needs, letters of credit, distributions to partners and general partnership purposes, including future acquisitions and expansions. At December 31, 2003 we had $30.3 million of letters of credit issued under the $50 million working capital and letter of credit facility, leaving approximately $19.7 million available for

34

future issuances of letters of credit and/or cash borrowings. The aggregate amount of borrowings under the working capital and letter of credit facility is subject to a borrowing base requirement relating to the amount of our cash and eligible receivables (as defined in the credit agreement), and there is a $25.0 million sublimit for cash borrowings. This facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital and letter of credit facility may be re-borrowed. We are required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.

        The obligations under the bank credit facility are secured by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of our equity interests in certain of our subsidiaries, and ranks pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by certain of our subsidiaries and by us. We may prepay all loans under the bank credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

        Indebtedness under the acquisition facility and the working capital and letter of credit facility bear interest at our operating partnership's option at the administrative agent's reference rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.00%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.50% to 2.00% per annum, plus a fronting fee of 0.125% per annum. Our operating partnership will incur quarterly commitment fees based on the unused amount of the credit facilities.

        The credit agreement prohibits us from declaring distributions to unitholders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. In addition, the bank credit facility contains various covenants that, among other restrictions, limit our operating partnership's ability to:

•

incur indebtedness;



•

grant or assume liens;



•

make certain investments;



•

sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;



•

make distributions;



•

change the nature of its business;



•

enter into certain commodity contracts;



•

make certain amendments to our operating partnership's partnership agreement; and



•

engage in transactions with affiliates.

        The bank credit facility also contains covenants requiring us to maintain:

•

a maximum ratio of total funded debt to consolidated EBITDA (each as defined in the bank credit facility), measured quarterly on a rolling four-quarter basis, of 3.75 to 1 through March 31, 2004, declining to 3.5 to 1 beginning June 30, 2004, pro forma for any asset acquisitions;



•

a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four quarter basis, equal to 3.50 to 1;



•

minimum current ratio (as defined in the credit agreement), measured quarterly, of 1 to 1; and



•

a minimum tangible net worth (as defined in the credit agreement) of $60 million, plus one-half of certain equity contribution proceeds received after December 31, 2002.

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        Each of the following will be an event of default under the bank credit facility:

•

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



•

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



•

certain judgments against us or any of our subsidiaries, in excess of certain allowances;



•

certain ERISA events involving us or our subsidiaries;



•

cross defaults to certain material indebtedness;



•

certain bankruptcy or insolvency events involving us or our subsidiaries;



•

a change in control (as defined in the credit agreement); and



•

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

        Senior Secured Notes.    In June 2003, our operating partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million aggregate principal amount of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, our operating partnership issued $10.0 million aggregate principal amount of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years.

        The following is a summary of the material terms of the senior secured notes.

        The notes represent senior secured obligations of our operating partnership and will rank at least pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with the obligations of the operating partnership under the credit facility, by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of our equity interests in certain of our subsidiaries. The senior secured notes are guaranteed by our operating partnership's subsidiaries and us.

        The senior secured notes are redeemable, at our operating partnership's option and subject to certain notice requirements, at a purchase price equal to 100% of the principal amount together with accrued interest, plus a make-whole amount determined in accordance with the master shelf agreement.

        The master shelf agreement relating to the notes contains substantially the same covenants and events of default as the bank credit facility.

        If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of more than 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable.

        The Operating Partnership was in compliance with all debt covenants at December 31, 2003 and 2002.

        Intercreditor and Collateral Agency Agreement.    In connection with the execution of the master shelf agreement in June 2003, the lenders under the bank credit facility and the initial purchasers of the senior secured notes entered into an Intercreditor and Collateral Agency Agreement, which was acknowledged and agreed to by our operating partnership and its subsidiaries. This agreement appointed Union Bank of California, N.A. to act as collateral agent and authorized Union Bank to execute various security documents on behalf of the lenders under the bank credit facility and the initial purchases of the senior secured notes. This agreement specifies various rights and obligations of

36

lenders under the bank credit facility, holders of senior secured notes and the other parties thereto in respect of the collateral securing Crosstex Energy Services, L.P.'s obligations under the bank credit facility and the master shelf agreement.

Credit Risk and Significant Customers

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

        During the year ended December 31, 2003, we had one customer that individually accounted for more than 10% of consolidated revenues. During the year ended December 31, 2003, Kinder Morgan Tejas accounted for 20.5% of our consolidated revenue. While this customer represents a significant percentage of consolidated revenues, the loss of this customer would not have material impact on our results of operations.

Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2001, 2002, or 2003. 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.

Environmental

        Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are 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."

Recent Accounting Pronouncements

        In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement establishes standards for accounting for obligations associated with the retirement of tangible long-lived assets. This standard was adopted by us on January 1, 2003. We do not presently have any significant legal asset retirement obligations, and accordingly, the adoption of SFAS No. 143 had no impact on our results of operations or financial condition.

        SFAS No 148, Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123, SFAS No. 148 amends SFAS No. 123 and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. SFAS No. 148 permits two additional transition methods for entities that adopt the fair value based method, these methods allow Companies to avoid the ramp-up effect arising from prospective application of the fair value based method. This Statement is effective for financial statements for fiscal years ending after December 15, 2002. We have complied with the disclosure provisions of the Statement in our financial statements.

        In January 2003, the FASB issued Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others. FIN

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No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ended after December 15, 2002. The adoption of this statement had no impact on our results of operations or financial condition.

        In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No 51. In December 2003, the FASB issued FIN No. 46R which clarified certain issues identified in FIN 46. FIN No. 46R requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after March 15, 2004. We are currently evaluating our ownership interests in joint ventures and limited partnerships that are currently accounted for using the equity method of accounting to determine whether FIN No. 46R will require the consolidation of any of these investments, however, we currently believe that one of our joint venture interests, as described in Note 4 to the financial statements, will be consolidated in our financial statements when FIN No. 46R is adopted in March 2004.

        The FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," ("SFAS No. 150") in May 2003. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. We have no financial instruments which are subject to SFAS No. 150.

Disclosure Regarding Forward-Looking Statements

        This report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 31E of the Securities Exchange Act of 1934, as amended. Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "forecast," "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. In addition to specific uncertainties discussed elsewhere in this Form 10-K, the following risks and uncertainties may affect our performance and results of operations:

•

we may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to pay the minimum quarterly distribution each quarter;



•

if we are unable to contract for new natural gas supplies, we will be unable to maintain or increase the throughput levels in our natural gas gathering systems and asset utilization rates at our treating and processing plants to offset the natural decline in reserves;



•

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

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•

our future success will depend in part on our ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;



•

Crosstex Energy, Inc. owns approximately 55% aggregate limited partner interest of us and it owns and controls our general partner, thereby effectively controlling all limited partnership decisions; conflicts of interest may arise in the future between Crosstex Energy, Inc. and its affiliates, including our general partner, and our partnership or any of our unitholders;



•

since we are not the operator of certain of our assets, the success of the activities conducted at such assets are outside our control;



•

we operate in very competitive markets and encounter significant competition for natural gas supplies and markets;



•

we are subject to risk of loss resulting from nonpayment or nonperformance by our customers or counterparties;



•

we may not be able to retain existing customers, especially key customers, or acquire new customers at rates sufficient to maintain our current revenues and cash flows;



•

the construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital and subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;



•

our business is subject to many hazards and operational risks, some of which may not be covered by insurance; and



•

we are subject to extensive and changing federal, state and local laws and regulations designed to protect the environment, and these laws and regulations could impose liability for remediation costs and civil or criminal penalties for non-compliance.

        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.

        Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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. We face market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas we sell; and for the portion of the natural gas we process and for which we have taken the processing risk, we are at risk for the difference in the value of the NGL products we produce versus the value of the gas used in fuel and shrinkage in their production. We also incur credit risks and risks related to interest rate variations.

        Commodity Price Risk.    Approximately 8.4% of the natural gas we market 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 gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 16% of the gas we purchased during the year ended December 31, 2003. Our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the year ended December 31, 2003, a $0.01 per gallon change in NGL prices

39

offset by a change of $0.10 per MMBtu in the price of natural gas would have changed our processing margin by $170,000. Changes in natural gas prices indirectly may impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.

        Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee. Hedges to protect our processing margins are generally for a more limited time frame than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas. Such hedges generally involve taking a short position with regard to the relevant liquids and an offsetting short position in the required volume of natural gas.

        The use of financial instruments may expose us 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) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform, as happened in the case of the Enron loss discussed above. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

        We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for certain of our producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

        For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts are also recorded in profit or loss on energy trading contracts.

        Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2003 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2004, with no single contract longer than 6 months. Our counterparties to hedging contracts include Williams Energy Services Company, Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, Duke Field Services, and Duke Energy Trading and Marketing. Changes in the fair value of our derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes

40

in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings.

        On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establishes limits, and monitors the appropriateness of these limits on an ongoing basis.

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

        Interest Rate Risk.    We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. At December 31, 2003, we had $20.0 million of indebtedness outstanding under floating rate debt. We have interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein we have swapped floating rates for fixed rates of 2.29% and the applicable margin through November 1, 2004. The impact of a 100 basis point increase in interest rates on our debt level as of December 31, 2003 would result in an increase in interest expense and a decrease in income before taxes of approximately $41,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at December 31, 2003.

Item 8. Financial Statements and Supplementary Data

        The Report of Independent Public Accountants, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-35 and S-1 of this Report and are incorporated herein by reference.

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

        None.

Item 9A. Controls And Procedures

        We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2003 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

        There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART III

Item 10. Directors and Executive Officers of the Registrant

        As is the case with many publicly traded partnerships, we do not have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Crosstex Energy GP, LLC. Our operational personnel are employees of the operating partnership. References to our general partner, unless the context otherwise requires, includes Crosstex Energy GP, LLC. References to our officers, directors and employees are references to the officers, directors and employees of Crosstex Energy GP, LLC. or the operating partnership.

        Unit-holders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unit-holders, as limited by our partnership agreement. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.

        The following table shows information for the directors and executive officers of Crosstex Energy GP, LLC. Executive officers and directors are elected annually and have held the following positions since the date of the closing of our initial public offering, except for Messrs. Davis and Lawrence who have held the following positions with the Crosstex Energy GP, LLC since its formation in July 2002, and Mr. Burke, who became a director in August 2003.

        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 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.

        James R. Wales, Executive Vice President—Southern Division, joined our predecessor in December 1996. As one of the founders of Sunrise Energy Services, Inc., he helped build Sunrise into a major national independent natural gas marketing company, with sales and service volumes in excess of 600,000 MMBtu/d. Mr. Wales started his career as an engineer with Union Carbide. In 1981, he joined Producers Gas Company, a subsidiary of Lear Petroleum Corp., and served as manager of its Mid-Continent office. In 1986, he joined Sunrise as Executive Vice President of Supply, Marketing and Transportation. From 1993 to 1994, Mr. Wales was the Chief Operating Officer of Triumph Natural

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Gas, Inc., a private midstream business. Prior to joining Crosstex, Mr. Wales was Vice President for Teco Gas Marketing Company. Mr. Wales holds a B.S. degree in Civil Engineering from the University of Michigan, and a Law degree from South Texas College of Law.

        A. Chris Aulds, Executive Vice President—Northern and Treating Divisions together with Barry E. Davis, participated in the management buyout of Comstock Natural Gas in December 1996. Mr. Aulds joined Comstock Natural Gas, Inc. in October 1994 as a result of the acquisition by Comstock of the assets and operations of Victoria Gas Corporation. Mr. Aulds joined Victoria in 1990 as Vice President responsible for gas supply, marketing and new business development and was directly involved in the providing of risk management services to gas producers. Prior to joining Victoria, Mr. Aulds was employed by Mobil Oil Corporation as a production engineer before being transferred to Mobil's gas marketing division in 1989. There he assisted in the creation and implementation of Mobil's third-party gas supply business segment. Mr. Aulds holds a B.S. degree in Petroleum Engineering from Texas Tech University.

        Jack M. Lafield, Executive Vice President—Corporate Development, joined our predecessor in August 2000. For five years prior to joining Crosstex, Mr. Lafield was Managing Director of Avia Energy, an energy consulting group, and was involved in all phases of acquiring, building, owning and operating midstream assets and natural gas reserves. He also provided project development and consulting in domestic and international energy projects to major industry and financing organizations, including development, engineering, financing, implementation and operations. Prior to consulting, Mr. Lafield held positions of President and Chief Executive Officer of Triumph Natural Gas, a private midstream business he founded, President and Chief Operating Officer of Nagasco, Inc. (a joint venture with Apache Corporation), President of Producers' Gas Company, and Senior Vice President of Lear Petroleum Corp. Mr. Lafield holds a B.S. degree in Chemical Engineering from Texas A&M University, and is a graduate of the Executive Program at Stanford University.

        William W. Davis, Executive Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has 25 years of finance and accounting experience. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President—Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and 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.

        Michael P. Scott, Senior Vice President—Technical Services, joined our predecessor in July 2001. Before joining our predecessor, Mr. Scott held various positions at Aquila Gas Pipeline Corporation, including Director of Engineering from 1992 to 2001, Director of Operations from 1990 to 1992, and Director of Project Development from 1989 to 1990. Prior to Aquila, Mr. Scott held various project development and engineering positions at Cabot Corporation/Cabot Transmission, Perry Gas Processors and General Electric. Mr. Scott holds a B.S. degree in Mechanical Engineering from Oklahoma State University.

        Frank M. Burke joined Crosstex Energy GP, LLC as a director in August 2003. Mr. Burke has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company Ltd., a private investment company located in Dallas, Texas, since 1984. Prior to that, Mr. Burke was a partner in Peat, Marwick, Mitchell & Co. (now KPMG). He is a member of the National Petroleum Council and also serves as a director of Arch Coal, Inc., Dorchester Minerals, L.P., Kaneb Pipe Line Partners, L.P., Xanser Corporation and Kaneb Services LLC. Mr. Burke received his Bachelor of Business Administration and Master of Business Administration from Texas Tech University and his Juris Doctor from Southern Methodist University. He is a Certified Public Accountant and member of the State Bar of Texas.

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        C. Roland Haden joined us as a director upon the completion of our initial public offering. Mr. Haden held the positions of Vice Chancellor of the Texas A&M System, Director of the Texas Engineering Experiment Station and Dean of Look College of Engineering at Texas A&M University from 1993 to 2002. Prior to joining Texas A&M University, Mr. Haden served as Vice Chancellor for Academic Affairs and Provost of Louisiana State University from 1991 to 1993 and held various positions with Arizona State University, including Dean and Professor of Engineering & Applied Sciences from 1989 to 1991, Provost, ASU West Campus from 1988 to 1989, Vice President for Academic Affairs from 1987 to 1988 and Dean and Professor of Engineering and Applied Sciences from 1978 to 1987. Mr. Haden formerly served as a director of Square D Company, a Fortune 500 electrical manufacturing company, as a director of E-Systems, a Fortune 500 defense contractor, and as a member of the Telecommunications Advisory Board of A.T. Kearney, a nationally ranked consulting firm. He has been a director of Inter-tel, Inc., a leading telecommunications company, since 1983. Mr. Haden holds a bachelor's degree from the University of Texas, Arlington, a Masters degree from the California Institute of Technology, and a Ph.D. from the University of Texas, Austin, all in electrical engineering.

        Bryan H. Lawrence, Chairman of the Board, joined our predecessor as a director in May 2000. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of D&K Healthcare Resources, Inc., Hallador Petroleum Company, TransMontaigne Inc., and Vintage Petroleum, Inc. (each a United States publicly traded company) and Cavell Energy Corp. (a Canadian publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor B.V., Camden Resources, Inc., ESI Energy Services Inc., Ellora Energy Inc., Dernick Resources Inc., Cinco Natural Resources Corp., Peak Energy Resources, Inc., Approach Resources Inc., Nytis Exploration Co., and Compass Petroleum Ltd. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.

        Sheldon B. Lubar joined us as a director upon the completion of our initial public offering. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar has also been a Director of C2, Inc., a logistics and manufacturing company, since 1995, MGIC Investment Corporation, a mortgage insurance company, since 1991, Grant Prideco, Inc., an energy services company, since 2000, and Weatherford International, Inc., an energy services company, since 1995. Mr. Lubar holds a bachelor's degree in Business Administration and a Law degree from the University of Wisconsin—Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin—Milwaukee.

        Robert F. Murchison joined us as a director upon the completion of our initial public offering. Mr. Murchison has been the President of the general partner of Murchison Capital Partners, L.P., a private equity investment partnership since 1992. Prior to founding Murchison Capital Partners, L.P., Mr. Murchison held various positions with Romacorp, Inc., the franchisor and operator of Tony Roma's restaurants, including Chief Executive Officer from 1984 to 1986 and Chairman of the board of directors from 1984 to 1993. He served as a director of Cenergy Corporation, an oil and gas exploration and production company, from 1984 to 1987, Conquest Exploration Company from 1987 to 1991 and has served as a director of TNW Corporation, a short line railroad holding company, since 1981 and Tecon Corporation, a holding company with holdings in real estate development, investor

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owned water utilities, rail car repair and the fund of funds management business, since 1978. Mr. Murchison holds a bachelor's degree in history from Yale University.

        Stephen A. Wells joined us as a director upon the completion of our initial public offering. Mr. Wells has been the President of Wells Resources, Inc., a private oil, gas and ranching company since 1983. Mr. Wells has served in executive management positions with various energy companies, with an emphasis in oil field services. He served as Chief Executive Officer and director of Grasso Corporation, a contract production management company, from 1992 to 1994, Chief Executive Officer and director of Coastwide Energy Services, Inc. from 1993 to 1996, and President, Chief Executive Officer and director of Wells Strathclyde Company, an oil field services company he co-founded from 1978 to 1982. Mr. Wells also serves as a director and audit committee chair of Oil States International and as a director and audit committee chair of Pogo Producing Company. Mr. Wells holds a bachelor's degree in accounting from Abilene Christian University.

"Independent" Directors

        Messrs. Burke, Haden, Lubar, Murchison and Wells qualify as "independent" in accordance with the published listing requirements of The NASDAQ Stock Market (NASDAQ). The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

        In addition, the members of the Audit Committee of the board of directors of our general partner also each qualify as "independent" under special standards established by the Securities and Exchange Commission (SEC) for members of audit committees, and the Audit Committee includes at least one member who is determined by the board of directors to meet the qualifications of an "audit committee financial expert" in accordance with SEC rules, including that the person meets the relevant definition of an "independent" director. Mr. Burke is the independent director who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Burke's experience and understanding with respect to certain accounting and auditing matters. The designation does not impose on Mr. Burke any duties, obligations or liability that are greater than are generally imposed on him as a member of the Audit Committee and board of directors, and his designation as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.

Board Committees

        The board of directors of Crosstex Energy GP, LLC currently has, and appoints the members of, standing Audit, Compensation and Conflicts Committees. Each member of the Audit, Compensation and Conflicts Committees is an independent director in accordance with NASDAQ standards described above. Each of the board committees has a written charter approved by the board. Copies of the charters will be provided to any person, without charge, upon request. Contact Kathie Keller at 214-721-9327 to request a copy of a charter or send your request to Crosstex Energy, L.P., Attn: Kathie Keller, 2501 Cedar Springs, Suite 600, Dallas, Texas 75201.

        The Audit Committee of Crosstex Energy GP, LLC, comprised of Messrs. Burke (chair), Wells and Haden, assists the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors.

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        Two members of the board of directors of Crosstex Energy GP, LLC, namely Messrs. Haden (chair) and Wells, serve on a conflicts committee, which reviews specific matters that the board believes may involve conflicts of interest between our general partner and Crosstex Energy, L.P. The conflicts committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee are not officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unit-holders.

        The Compensation Committee of Crosstex Energy GP, LLC, comprised of Messrs. Lubar (chair) and Murchison, oversees compensation decisions for the officers of the General Partner as well as the compensation plans described herein

Code of Ethics

        Crosstex Energy GP, LLC has adopted a Code of Business Conduct and Ethics applicable to all officers, and its independent directors, who are not employees of Crosstex Energy GP, LLC, with regard to Partnership-related activities. The Code of Business Conduct and Ethics incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate our expectations of our and Crosstex Energy GP, LLC's 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 our Code of Business Conduct and Ethics will be provided to any person, without charge, upon request. Contact Kathie Keller at 214-721-9327 to request a copy of a charter or send your request to Crosstex Energy, L.P., Attn: Kathie Keller, 2501 Cedar Springs, Suite 600, Dallas, Texas 75201. If any substantive amendments are made to the Code of Business Conduct and Ethics or if we or Crosstex Energy GP, LLC grant any waiver, including any implicit waiver, from a provision of the code to any of Crosstex Energy GP, LLC's executive officers and directors, we will disclose the nature of such amendment or waiver in a report on Form 8-K.

Section 16(a)—Beneficial Ownership Reporting Compliance

        Section 16(a) of the Securities Exchange Act of 1934 requires the directors and certain officers of the General Partner and any 10% beneficial owners of the Partnership to send reports of their beneficial ownership of Common Units and changes in beneficial ownership to the Securities and Exchange Commission. Based on our records, we believe that during fiscal 2003 all of such reporting persons complied with all Section 16(a) filing requirements applicable to them.

Reimbursement of Expenses of our General Partner and its Affiliates

        Our general partner does not receive any management fee or other compensation in connection with its management of Crosstex Energy, L.P. However, our general partner performs services for us and is reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the twelve month period ending December 31, 2003, the amount which we reimbursed the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf could not exceed $6.0 million. This reimbursement cap did not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on behalf of the partnership. See Item 13. "Certain Relationships and Related Transactions."

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Item 11. Executive Compensation

        The following table sets forth certain compensation information for our Chief Executive Officer and the five other most highly compensated executive officers in 2002 and 2003. We reimburse our general partner and its affiliates for expenses incurred on our behalf, including the costs of officer compensation allocable to us. The named executive officers have also received certain equity-based awards from our general partner's general partner. The Partnership was formed in July 2002 but conducted no business until mid-December 2002. As such, the compensation set forth below includes salary and bonus information paid to each of the named executive officers by the Partnership and its predecessor, prior to mid-December 2002.

Summary Compensation Table

(1)

Reflects the aggregate salary paid by the registrant and its predecessor for fiscal 2002 and 2003. The portion of the amount shown paid by the registrant subsequent to the closing of its initial public offering on December 17, 2002 for each of Messrs. Davis, Wales, Aulds, Lafield, W. Davis, and Scott was $8,396, $7,128, $7,128, $6,703, $6,703 and $5,596, respectively.

(2)

Performance bonuses, for fiscal 2002 were earned by the executive officers for service to the registrant's predecessor prior to the closing of its initial public offering.

(3)

Executive officers received equity-based awards from our general partner in 2002 and 2003. For a description of awards granted to date under the Long-Term Incentive Plan. See "—Long-Term Incentive Plan."

Employment Agreements

        The executive officers of the general partner of our general partner, including Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, have entered into employment agreements with Crosstex Energy, L.P. The following is a summary of the material provisions of those employment agreements. All of these employment agreements are substantially similar, with certain exceptions as set forth below.

        Each of the employment agreements has an initial term that expires two years from the effective date, but will automatically be extended such that the remaining term of the agreements will not be less than one year. The employment agreements provide for a base annual salary of $218,400, $187,200,

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$187,200, $176,00, $176,000 and $156,000 for Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, respectively, for 2004.

        Except in the event of our becoming bankrupt or ceasing operations, termination for cause or termination by the employee other than for good reason, the employment agreements provide for continued salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement. If a change in control occurs during the term of an employee's employment and either party to the agreement terminates the employee's employment as a result thereof, the employee will be entitled to receive salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement.

        The employment agreements also provide for a noncompetition period that will continue until the later of one year after the termination of the employee's employment or the date on which the employee is no longer entitled to receive severance payments under the employment agreement. During the noncompetition period, the employees are generally prohibited from engaging in any business that competes with us or our affiliates in areas in which we conduct business as of the date of termination and from soliciting or inducing any of our employees to terminate their employment with us or accept employment with anyone else or interfere in a similar manner with our business.

Long-Term Incentive Plan

        Crosstex Energy GP, LLC adopted a long-term incentive plan for employees and directors of Crosstex Energy GP, LLC and its affiliates who perform services for us.

        The long-term incentive plan consists of two components: restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 700,000 common units, 233,000 of which may be awarded in the form of restricted units and 467,000 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of Crosstex Energy GP, LLC's board of directors.

        Crosstex Energy GP, LLC's board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Crosstex Energy GP, LLC's board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unit-holder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

        Restricted Units.    A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. In the future, the compensation committee may make grants under the plan to employees and directors containing such terms as the compensation committee shall determine under the plan. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us, our general partner or Crosstex Energy GP, LLC.

        If a grantee's employment terminates for any reason, other than death, disability or retirement, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. If a grantee is a director and his membership on the board of directors is terminated for cause, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by Crosstex Energy GP, LLC in the open market, common units already owned by Crosstex Energy GP, LLC, common units acquired by Crosstex Energy GP, LLC directly from us or any other person or any combination of the foregoing. Crosstex

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Energy GP, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units which entitles the grantee to distributions attributable to the restricted units prior to vesting of such units.

        We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

        Unit Options.    The long-term incentive plan currently permits the grant of options covering common units. Unit options will have an exercise price that, in the discretion of the compensation committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner or Crosstex Energy GP, LLC or upon the achievement of specified financial objectives.

        Upon exercise of a unit option, Crosstex Energy GP, LLC will acquire common units in the open market or directly from us or any other person or use common units already owned by Crosstex Energy GP, LLC, or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Crosstex Energy GP, LLC will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unit-holders.

Option Grants

        There were no unit options granted to the named executive officers in 2003.

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Option Exercises and Year-End Option Values

        The following table provides information about the number of units issued upon option exercises by the named executive officers during 2003, and the value realized by the named executive officers. The table also provides information about the number and value of options that were held by the named executive officers at December 31, 2003.

Aggregated Option Exercise in Last Fiscal Year
and Fiscal Year End Option Values

        The closing price for the common units was $41.30.

Compensation of Directors

        Each director of Crosstex Energy GP, LLC who is not an employee of Crosstex Energy GP, LLC (except Mr. Lawrence) is paid an annual retainer fee of $25,000. Directors do not receive an attendance fee for each board meeting, but an attendance fee of $1,000 is paid to each director for each committee meeting he attends, except the audit committee members who receive $1,250 for each audit committee meeting. Directors are also reimbursed for related out-of-pocket expenses. Each committee chairman receives $2,500 annually, except the audit committee chairman who receives $3,500 annually. Barry E. Davis, as an officer of Crosstex Energy GP, LLC, is otherwise compensated for his services and therefore receives no separate compensation for his service as a director. Messrs. Haden, Lawrence, Lubar, Murchison and Wells also received a one-time grant of 10,000 options at an exercise price of $20 in 2003 and Messr. Burke received a one-time grant of 10,000 options at an exercise price of $36.29 (the unit closing price on the date of the grant).

Compensation Committee Interlocks And Insider Participation

        The Compensation Committee of the board of directors of Crosstex Energy GP, LLC determines compensation of the executive officers. Sheldon B. Lubar and Robert F. Murchison served as members of the Compensation Committee of the board of directors of Crosstex Energy GP, LLC upon the completion of our initial public offering.

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

        The following table shows the beneficial ownership of units of Crosstex Energy, L.P. as of February 28, 2004, held by:

•

each person who beneficially owns 5% or more of the units then outstanding;



•

all the directors of Crosstex Energy GP, LLC;



•

each named executive officer of Crosstex Energy GP, LLC; and

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•

all the directors and executive officers of Crosstex Energy GP, LLC as a group.