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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)

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 $48,524,500 on December 31, 2002, based on $21.40 per unit, the closing price of the Common Units as reported on the NASDAQ National Market on such date.

        At March 4, 2003, there were outstanding 2,633,000 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. (the "Registrant" or "Partnership") 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 primarily engaged in the midstream energy business focused on 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 1,700 miles of natural gas gathering and transmission pipelines, one natural gas processing plant (the "Gregory plant") connected to our Gregory gathering system, a smaller gas processing plant (the "Masters Creek plant") and 49 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 gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plants remove NGLs from a natural gas stream and, in the case of the Gregory Plant, fractionates, or separates, 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.

        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. See Note Thirteen to the consolidated financial statements for financial information about these business 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.

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        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

Midstream Division

        Gathering and Transmission.    Our natural gas gathering and transmission operations include over 1,700 miles of pipeline. We own a cryogenic gas processing facility with full liquid fractionation capabilities that is located on one of our major gathering systems north of Corpus Christi, Texas. For the year ended December 31, 2002, we gathered and transported approximately 368,177 Mcf/d of natural gas. Set forth below is a discussion of our principal pipeline systems.

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Gulf Coast System. 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, 2002, we were purchasing gas from over 60 producers primarily pursuant to month-to-month contracts and were reselling the natural gas to over 10 customers primarily pursuant to short-term or month-to-month arrangements. Beginning in July 2002, we started supplying natural gas to Entex (the natural gas utility for the City of Houston) under a two year contract. For the year ended December 31, 2002, approximately 92% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder were 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.



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Corpus Christi System. 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, 2002, we were purchasing natural gas from approximately 29 producers generally on month-to-month or short-term arrangements. For the year ended December 31, 2002, 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 its customers include multiple major refineries and other industrial installations, as well as the local electric utility. As of December 31, 2002, we were selling gas to over 10 customers primarily pursuant to contracts that expire at various times between 2003 and 2006. For the year ended December 31, 2002, all of the natural gas volumes we sold were sold at a fixed price relative to an index. New customers added since the acquisition of this system have increased our sales volumes by 50,000 Mcf/d, replacing less profitable sales volumes that have been discontinued. Additionally, in December 2001 we entered into an agreement to provide transportation services to Calpine Energy Services, LP, the owner of a co-generation facility in Corpus Christi. The Calpine facility adds significantly to system demand under a 15 year contract that includes minimum annual payments to us in exchange for providing firm capacity of up to 100,000 MMBtu/d. This 500 megawatt co-generation facility will receive gas supply solely through two interconnections to the Corpus Christi transmission system.



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Gregory Gathering System. We generate operating profits in our Gregory gathering system and our Gregory processing plant through the margins earned by purchasing, gathering, transporting

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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, 2002, we were purchasing gas from over 40 producers primarily pursuant to month-to-month contracts, and for the year ended December 31, 2002, approximately 92% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder were purchased at percentage of an index. The gas is delivered to the Gregory plant where the residue gas is sold to one customer pursuant to a contract expiring in 2006 at a price based on a fixed price relative to a monthly index. Liquids produced from processing are sold under two contracts, one expiring in 2007, and the other expiring in March 2004.

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



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For the year ended December 31, 2002, we purchased approximately 44% 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. 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.



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For the year ended December 31, 2002, we purchased approximately 56% 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. We anticipate purchasing increasing percentages of gas under fixed fee arrangements as opposed to contracts under which the processing economics are for our account.




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Arkoma Gathering System. 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.

        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 30 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.

        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.

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        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. The plants we operate are primarily amine plants. 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. Our 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. In addition, our membrane plants use a molecular filter to separate carbon dioxide and hydrogen sulfide from natural gas.

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.



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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

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utility consumers in an effort to increase our operating margins. For the year ended December 31, 2002, approximately 63% 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 modified the Gregory system by adding a by-pass around our Gregory processing plant which allowed us to deliver an additional 30,000 Mcf/d of gas to the plant tailgate without processing. Our recent acquisition from Florida Gas Transmission has facilitated establishing 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 addition to serving new markets in Florida. We are also evaluating the economic feasibility of increasing the capacity of our Gregory processing plant to 150,000 Mcf/d, a 76% increase over the current capacity, and marketing the additional gas through our Corpus Christi and Gulf Coast systems.

Recent Acquisitions and New Construction

        In December 2002, we acquired the Vanderbilt System from Devon Energy Corporation for $12.0 million, and the 50% operating interest in a treating plant (the Will-O-Mills plant) in which we already owned a 50% non-operating interest, for $2.2 million. We also recently formed a joint venture to construct a gathering system in an area of the Barnett Shale gas play at an initial cost of $3.0 million. See Item 2. "Properties."

Industry Overview

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

        The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-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,

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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. Natural gas is described as dry or wet depending on its NGL content. These are relative terms, but as generally used, a wet gas may contain two gallons or more of NGLs per Mcf, whereas a dry gas usually contains less than one gallon of recoverable liquids per Mcf. Most wet natural gas 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 NGLs and contaminants removed to very low concentrations. 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.

Risk Management

        It is our policy that as we purchase natural gas, we establish a margin by selling natural gas for physical delivery to third-party users. 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. For that portion of the gas we purchase which we buy on a percentage-of-index or percentage-of-proceeds contracts, since our margin can vary with the price of natural gas, we may hedge our margin. We also enter into similar contracts to hedge prices on behalf of producers we serve, using over-the-counter derivative instruments or by entering into a future delivery obligation under futures contracts on the New York Mercantile Exchange.

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. Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. 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 gas treating operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant leasing and operations similar to ours. We also face competition from vendors of used equipment that occasionally lease and operate plants for

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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.

Regulation

        Intrastate Pipeline Regulation.    Our intrastate natural gas pipeline operations generally are not subject to rate 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. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGA, which regulates, among other things, the provision 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.

        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.

        Pipeline Integrity Rules recently implemented by the TRRC require a pipeline operator to prove operational safety of a pipeline segment on a periodic basis. The rules offer two methods of proving a pipeline's integrity; Direct (Risk-Based) Assessment or Prescriptive Testing. Risk-Based Assessment proves a pipeline's integrity through documentation (including construction, testing and operating records) and Prescriptive Testing proves integrity through physical testing (an in-line inspection or hydrostatic pressure test). Crosstex intends to use the Risk-Based Assessment method to achieve full compliance in a cost effective manner in conjunction with Prescriptively Testing of pipeline segments in high consequence areas.

        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

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classification and regulation of our gathering 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.

        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. FERC is continually proposing and implementing new rules and regulations affecting 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. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations. 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 of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionization 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 our cost of planning, constructing, and operating our plants, pipelines, and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities.

        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.

        Hazardous Substance and Waste.    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

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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 our ordinary operations we will 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.

        We also generate both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the 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.

        We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. 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.

        Air Emissions.    Our operations are 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. 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 our facilities. 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 results of operations.

        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

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operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

        Safety Regulations.    Portions of our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, 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. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements.

Office Facilities

        In addition to our gathering and treating facilities discussed above, we occupy approximately 17,000 square feet of space at our executive offices in Dallas, Texas under a lease expiring in November 2004.

Employees

        As of December 31, 2002, our operating partnership, Crosstex Energy Services, L.P., had approximately 126 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.

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Item 2. Properties

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

(1)

Acquired during 2002.

Midstream Division

        Our primary Midstream assets are four major systems and a natural gas processing plant along the Texas Gulf Coast and one gathering system in eastern Oklahoma, which in the aggregate consist of approximately 1,700 miles of gathering and transmission pipelines. For the year ended December 31,

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2002, we gathered and transported approximately 368,177 Mcf/d of natural gas. Certain information regarding our primary assets in our Midstream division is summarized in the table below:

(1)

The throughput on our Gregory gathering system is limited by the processing capacity of the Gregory processing plant, which is currently 85,000 Mcf/d, and a by-pass around the Gregory processing plant which has a capacity of 30,000 Mcf/d.

        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 76 receipt points and five treating and processing plants operated by third parties. This system has three delivery laterals—an 8 inch lateral into the Victoria area, a 12 inch lateral into the Point Comfort area, and a 16 inch lateral into the Bay City area—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 also hold firm transportation capacity on the TXU Lone Star pipeline, which provides 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 had average throughput of approximately 103,323 MMBtu/d for the year ended December 31, 2002.

        Vanderbilt System.    On December 19, 2002, we acquired the Vanderbilt System from a subsidiary of Devon Energy Corporation. The Vanderbilt system has approximately 200 miles of gathering pipeline located near our Gulf Coast system. The purchase price was $12.0 million. The pipeline ranges in diameter from 4 to 14 inches and had throughput at the time of acquisition of approximately 32,000 MMBtu/d. Gathered natural gas currently flows to the Exxon Katy plant, which is scheduled to close in November 2003. We have a contract to deliver the natural gas from this gathering system to the Formosa Hydrocarbons processing plant at Point Comfort, Texas beginning in the spring of 2003.

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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 extends from supply points in south Texas to markets in Corpus Christi, Texas. Its gathering and transmission pipelines range in diameter from 4 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, (the CCNG Acquisition), for an aggregate purchase price of approximately $30 million. The main lines comprising the Corpus Christi system were constructed in the 1940's with additional expansions throughout the 1990's. We believe the expected remaining life of the pipeline system is approximately 50 years.

        Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 12 treating and processing plants and third-party gathering systems and pipelines. 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 may deliver natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system had an average throughput of approximately 157,918 MMBtu/d for the year ended December 31, 2002.

        In June 2002, we acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows us access to the Florida Gas transmission mainline and accordingly the ability to reach markets in Florida. 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 December, 2002, after completion of the interconnect between our systems and Florida Gas Transmission Company, we sold an average daily quantity of 43,000 MMBtu/d into the Florida markets.

        Gregory Gathering System.    We acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the CCNG Acquisition. The plant 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 2 inches to 18 inches. Until early 2002, all of the gas from the gathering system had been delivered to the inlet of the processing plant. Accordingly, the capacity of the gathering system was constrained by the inlet capacity of the plant. In January 2002, we constructed a by-pass around the plant so that additional gas can be delivered to the plant tailgate without processing. The gathering system had average throughput of approximately 106,543 MMBtu/d for the year ended December 31, 2002 compared to approximately 76,500 MMBtu of gas per day at the time of our acquisition. The Gregory gathering system was constructed in the 1980's and we believe the expected remaining life of the pipeline system is approximately 50 years.

        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 had an average throughput of approximately 83,624 MMBtu/d for the year ended December 31, 2002. At the time of our acquisition, the plant was processing approximately 86,247 MMBtu of gas per day. The Gregory processing plant was constructed in the 1980's and expanded and upgraded in 1998. We believe the expected remaining life of the Gregory processing plant is approximately 20 years. As part of the CCNG Acquisition, we entered into a contract whereby all of the processed natural gas coming from our Gregory processing plant is sold to a subsidiary of Kinder Morgan under a contract that expires in March, 2006.

        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

13

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 to 10 inches. This low-pressure system gathers gas from approximately 146 wells to three compressor stations for discharge to a mainline transmission pipeline. This system had average throughput of approximately 10,785 MMBtu/d for the year ended December 31, 2002.

        Other Systems.    We own several small gathering systems totaling approximately 330 miles, including our Manziel system in Wood County, Texas, our San Augustine system in San Augustine County, Texas, our Freestone Rusk system in Freestone County, Texas, and our Jack Starr and North Edna systems in Jackson County, Texas. 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. 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 4,900 MMBtu/d for the year ended December 31, 2002. In addition to these systems, we own various smaller gathering and transmission systems located in Texas and New Mexico.

Treating Division

        As of December 31, 2002, we owned 49 treating plants, 26 of which were operated by our personnel, 9 of which were operated by producers, and 14 of which were held in inventory. We entered the treating business in 1998 with the strategic acquisition of WRA Gas Services. In October 2001, we completed our largest acquisition of gas treating assets with the acquisition of Millenium Gas Services, which added 11 treating plants, four of which were in operation and seven of which were placed in our inventory.

        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 is high in carbon dioxide. The majority of our active plants are treating gas from the Wilcox and Edwards formations, both of which are deeper formations that are high in carbon dioxide. Our active treating facilities include 33 amine plants and two 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. If the producer operates the facility, we receive a fixed monthly fee.

        In addition to our treating plants, we have three gathering systems in our treating division 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, including the Will-O-Mills plant in Val Verde County, Texas, which we consolidated ownership of in December 2002. The diameter of these gathering pipelines ranges from 2 to 6 inches. These gathering assets in the aggregate had average throughput of approximately 23,396 MMBtu/d for the year ended December 31, 2002. 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, we 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.

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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 we own in fee.

        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, our general partner believes that these consents, permits or authorizations will be obtained or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

        Our general partner believes that we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by affiliates of our predecessor until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. Our general partner believes 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, 2002.

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PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

        The Partnership's common units representing limited partner interests in the Partnership are listed on the NASDAQ National Market under the symbol "XTEX". The common units began trading on December 12, 2002, at an initial public offering price of $20.00 per common unit. On March 4, 2003, the market price for the common units was 23.95 per unit and there were approximately 2,610 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 sets forth, for the portion of the fourth quarter 2002 in which the common units were traded, the range of high and low closing sales prices for the common units as reported by the NASDAQ National Market, and the amount of cash distribution paid per common unit for the portion of the fourth quarter 2002 commencing December 17, 2002, the date of closing of the initial public offering.

        The Partnership has also issued subordinated units representing limited partner interests in the Partnership, all of which are held by an affiliate of the general partner, for which there is no established public trading market.

        Beginning with the quarter ending March 31, 2003, we will distribute, on a quarterly basis, all of our available cash. Available cash generally means, for any of our fiscal quarters, all cash on hand at the end of the quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner 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 unitholders and our general partner for any one or more of the next four quarters.

        Minimum quarterly distributions are $0.50 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. We will adjust the minimum quarterly distribution for our initial distribution by approximately $.07 for the period from the closing of our initial public offering on December 17, 2002 through March 31, 2003.

        The subordination period will end if certain financial tests contained in the partnership agreement are met for three consecutive four-quarter periods (the "testing period"), but no sooner than December 31, 2007. During the first quarter after the end of the subordination period, all of the subordinated units will convert into Common Units. Early conversion of a portion of the subordinated units may occur if the financial tests are satisfied before December 31, 2007.

        In addition to distributions on its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally

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our general partner is entitled to 13% of amounts we distribute in excess of $0.50 per unit, 23% of the amounts we distribute in excess of $0.625 per unit and 48% of amounts we distribute in excess of $0.75 per unit.

        Under the terms of our bank credit agreement and letter of credit and borrowing facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. "Management's Discussion and Analysis—Liquidity and Capital Resources."

Recent Sales of Unregistered Securities

        On December 17, 2002 and in offerings exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, the Partnership converted the existing limited partner interest in the Partnership owned by Crosstex Energy Holdings Inc. into 333,000 common units and 4,667,000 subordinated units in connection with the contribution of the interests of our subsidiaries which hold our operating assets. There have been no other sales of unregistered securities of the Partnership within the past three years.

Use of Proceeds From Registered Securities

        On December 12, 2002, the Partnership's registration statement on Form S-1 (Registration No. 333-97779) was declared effective by the Securities and Exchange Commission in connection with the public offering of 2,000,000 common units representing limited partner interests in the Partnership (plus up to 300,000 additional common units upon the exercise of the underwriters' over-allotment option), which commenced on December 17, 2002. The initial public offering did not terminate prior to the sale of all the securities registered. The underwriters of the offering were A. G. Edwards & Sons, Inc., Raymond James & Associates, Inc., and RBC Dain Rauscher Inc. The initial public offering consisted solely of the one class of common units. The number of securities registered, including the Common Units subject to the underwriters' over-allotment option, was 2,300,000, all of which have been sold to the public.

        The price to public, underwriting discounts and commissions, and proceeds to the Partnership are set forth in the following table:

(1)

Before deducting expenses of $2.59 million paid by the Partnership.

        The net proceeds of the initial public offering of the common units, after deducting expenses of $2.59 million and underwriting discounts and commissions of $3.22 million, was $40.19 million. The Partnership distributed $2.50 million of the net proceeds from the sale of the common units in the initial public offering and the exercise of the underwriters' over-allotment to Crosstex Energy Holdings Inc., pursuant to the terms of the partnership agreement of the Partnership. The Partnership contributed the remainder of such net proceeds ($37.69 million) to the Operating Partnership. Net proceeds from the sale of common units in the initial public offering were used by the Operating Partnership to repay $33.00 million of outstanding borrowings under our existing credit facility, which replaced our predecessor's credit facility, and the remaining $4.69 million was added to the working capital of the Operating Partnership.

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        For additional information regarding the terms of the our existing credit facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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. As described in our historical financial statements, 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 audited 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 and the CCNG system, which includes the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, beginning in May 2001.

        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)

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

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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 Holdings 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, 2002, 73% of our gross margin was generated in the Midstream division, with the balance in the Treating division, and approximately 86% of our gross margin was generated in the Texas Gulf Coast region.

        Since our formation, we have grown significantly as a result of our construction and acquisition of gathering and transmission pipelines, treating and processing plants. From January 1, 2000 through December 31, 2002, we have invested approximately $115.1 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. We generate revenues from four primary sources:

•

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



•

processing natural gas at our processing plants;



•

providing producer services; and



•

treating natural gas at our treating plants.

        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. We attempt to execute all purchases and sales substantially concurrently. 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.

        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

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principal gathering and transmission systems and for our producer services business for the year ended December 31, 2002.

(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 contracts in accordance with EITF 02-03.

        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, 2002, we purchased approximately 44% 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. All of the processed natural gas is delivered to a single customer 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, 2002, we purchased approximately 56% of the natural gas volumes on our Gregory system at a spot or market price less a discount that includes a fixed 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.

        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 30 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 66% of the operating income in our Treating division for the year ended December 31, 2002;



•

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

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•

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

        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 will be dictated by the terms of our partnership agreement and our omnibus agreement with Crosstex Energy Holdings Inc. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to Crosstex Energy, L.P., and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, Crosstex Energy, L.P. Our partnership agreement provides that our general partner will determine the expenses that are allocable to Crosstex Energy, L.P. in any reasonable manner determined by our general partner in its sole discretion. For the first 12 months following this offering, the amount which we will reimburse our general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will 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.

        Crosstex Energy Holdings Inc. modified certain terms of certain outstanding options in the first quarter of 2003. These modifications will result in variable award accounting for the modified options. Based on an assumed unit value of $23 per unit, total compensation expense would be approximately $2.2 million, which will be recorded by Crosstex Energy, L.P. as non-cash stock based compensation expense in the first quarter of 2003. Compensation expense in future periods will be adjusted for changes in the unit market price.

        As described in the historical financial statements, 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. The transaction value of $21.9 million from the Yorktown investment was allocated to the assets and liabilities of our predecessor, which created increases in depreciation and amortization charges in periods subsequent to the Yorktown investment. The historical financial statements present separate reports for the entities before and after the transaction. For purposes of the analysis below, the year 2000 is considered one period, and the distinction in legal entities created by the transaction with Yorktown is ignored.

        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 the Arkoma gathering system, the Gulf Coast system, the CCNG system, and the Vanderbilt system.

        We acquired the Arkoma gathering system in September 2000 for a purchase price of approximately $10.5 million. The Arkoma system consisted of approximately 84 miles of gathering lines located in eastern Oklahoma. When acquired, the system was connected to approximately 115 wells, and purchased and resold approximately 12,000 MMBtu of gas per day.

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        We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million. The Gulf Coast system consisted of approximately 484 miles of gathering and transmission lines extending from south Texas to markets near the Houston area. At the time of the acquisition, it was transporting approximately 117,000 MMBtu of gas per day.

        We acquired the CCNG system in May 2001 for a purchase price of approximately $30 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.



•

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 NGL's, 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 Treating Division, whereas all of the other assets in the CCNG acquisition are included in the Midstream Division.

        We acquired the Vanderbilt System in December 2002 for a purchase price of $12 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.

        Certain assets and liabilities of our predecessor were not contributed to our new partnership. These included receivables associated with the Enron Corp. bankruptcy discussed below under "—Results of Operations—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts," and any cost or benefit associated with the various puts and calls entered into to protect the value of our predecessor's position relative to the Enron matter. The Jonesville processing plant, which has been largely inactive since the beginning of 2001, and the recently acquired Clarkson plant were also not contributed.

Commodity Price Risks

        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 6.2% in 2002) 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

23

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, on this portion of the gas, the changes are equal and offsetting. For the twelve month period ending December 31, 2003, we currently have hedges in place for approximately 66% of the gas we anticipate we will purchase on a percentage of index price, at an average price of $3.528 per MMBtu (excluding price-sensitive gas associated with the recently acquired Vanderbilt system).

        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.

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

        Revenues.    Midstream revenues were $437.7 million for the year ended December 31, 2002 compared to $362.7 million for the year ended December 31, 2001, an increase of $75.0 million, or 21%. Revenues were higher in 2002 than in 2001 due to the contribution of the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, which generated $120.5 million in additional revenues in 2002, as these assets were not acquired until May 2001. This increase was partially offset by a decline in natural gas prices from an average NYMEX settlement price of $4.273 per MMBtu in 2001 to $3.221 in 2002, which reduced revenues by $44.0 million.

        Treating revenues were $14.8 million for the year ended December 31, 2002 compared to $24.4 million in the same period in 2001, a decrease of $9.6 million, or 39%. The decline was due to the decrease in the price of natural gas, which accounted for $11.8 million of the decrease in treating revenues, a change in the contracts at certain plants to discontinue purchasing and reselling the treated gas and instead to receive only a treatment fee, which accounted for $4.8 million of the decrease, and a decrease in volume at one plant which accounted for $0.7 million of the decrease. This decline was partially offset by volume increases at two plants which generated an additional $5.6 million of revenue, 14 new plants placed in service in 2002 which collectively added $1.9 million, and the acquisition of the Rosita plant in May 2001, which generated an additional $0.3 million.

24

        Purchased Gas Costs.    Midstream purchased gas costs were $414.0 million for the year ended December 31, 2002 compared to $344.8 million for the year ended December 31, 2001, an increase of $69.2 million, or 20%. Costs increased by $113.7 million due to the Corpus Christi system, the Gregory gathering system and the Gregory processing plant. These facilities were purchased in May 2001 and only five months of their operating results are included in the 2001 period. This increase was partially offset by the decline in natural gas prices discussed above, which reduced costs by $44.0 million.

        Treating purchased gas costs were $5.8 million in 2002 compared to $18.1 million in 2001, a decrease of $12.3 million or 68%. The decrease in natural gas prices caused $7.2 million of the decline, certain contracts were restructured from a purchase and resale of the associated gas to a pure treatment fee, causing a decline of $4.8 million, and a decrease in treating volumes at one plant caused $0.7 million of the decline. This decrease was partially offset by costs at a new facility which created additional purchased gas costs of $.3 million.

        Operating Expenses.    Operating expenses were $10.5 million for the year ended December 31, 2002, compared to $7.4 million for the year ended December 31, 2001, an increase of $3.0 million, or 41%. The increase was primarily associated with the CCNG assets purchased in May 2001.

        General and Administrative Expenses.    General and administrative expenses were $8.5 million for the year ended December 31, 2002 compared to $5.9 million for the year ended December 31, 2001, an increase of $2.5 million, or 43%. 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 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 Contracts.    The profit on energy trading contracts 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. See "Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts."

        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

25

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.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

        Revenues.    Midstream revenues were $362.7 million for the year ended December 31, 2001 compared to $91.6 million for the year ended December 31, 2000, an increase of $271.1 million, or 296%. Revenues were higher in 2001 primarily due to:

•

ownership of the Arkoma system for the full year in 2001 as compared to only five months in 2000 contributed to an increase in revenues by $10.3 million;



•

ownership of the Gulf Coast system for the full year in 2001 as compared to only four months in 2000 contributed to an increase in revenues by $68.4 million;



•

the acquisition of the Corpus Christi system in May 2001 increased revenues by $117.0 million;



•

the acquisition of the Gregory gathering system in May 2001 increased revenues by $52.5 million; and



•

the acquisition of the Gregory processing plant in May 2001 increased revenues by $13.1 million. This was partially offset by the closure of the Jonesville plant, which contributed $4.0 million of revenues in 2000.

        The remaining increase in Midstream revenue is primarily attributable to the average price of natural gas in 2001 being approximately $0.39 per MMBtu higher than the average price in 2000.

        Revenues for natural gas treating were $24.4 million in 2001 compared to $23.3 million in 2000, an increase of $1.0 million, or 4%, due to new plants placed in service.

        Purchased Gas Costs.    Midstream division purchased gas costs for the year ended December 31, 2001 were $344.8 million compared to $86.4 million for the prior year, an increase of $258.3 million, or 299%. Costs were higher in 2001 primarily due to:

•

ownership of the Arkoma system for the full year in 2001 as compared to only five months in 2000 contributed to an increase in costs by $9.0 million;



•

ownership of the Gulf Coast system for the full year in 2001 as compared to only four months in 2000 increased costs by $65.3 million;



•

the acquisition of the Corpus Christi system in May 2001 increased costs by $114.0 million;



•

the acquisition of the Gregory gathering system in May 2001 increased costs by $49.9 million; and

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•

the acquisition of the Gregory processing plant in May 2001 increased costs by $9.9 million. This was partially offset by the shutdown of the Jonesville processing plant, which had $3.1 million of costs during 2000.

        Treating division purchased gas costs were $18.1 million in 2001 compared to $19.6 million in 2000, a decrease of $1.5 million, or 8%. In combination with the improvement in revenues in natural gas treating, the decrease in costs resulted in an improvement in gross margin of $2.5 million, or 68%. This improvement is primarily attributable to new plants placed in service for a fee, as opposed to purchase and resale of the gas.

        Operating Expenses.    Operating expenses were $7.4 million for the year ended December 31, 2001, compared to $2.3 million for the year ended December 31, 2000, an increase of $5.1 million, or 218%. Expenses were higher in 2001 than in 2000 primarily due to:

•

ownership of the Arkoma system for the full year in 2001 as compared to only five months in 2000 increased expenses by $0.6 million;



•

ownership of the Gulf Coast system for the full year in 2001 as compared to four months in 2000 increased expenses by $1.0 million;



•

the acquisition of the Corpus Christi system in May 2001 increased expenses by $0.9 million;



•

the acquisition of the Gregory gathering system increased expenses by $0.5 million;



•

the acquisition of the Gregory processing plant increased expenses by $1.3 million, and the shut down of the Jonesville plant in 2001 resulted in a decrease of $0.3 million; and



•

operating expenses for the Treating division increased by $0.8 million due to 10 new operated plants being placed in service.

        General and Administrative Expenses.    General and administrative expenses were $5.9 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.1 million, or 110%. The increase in general and administrative expense is associated with the increase in employees caused by our rapid growth and preparation for our initial public offering. Total personnel employed increased from 44 to 107 between the end of 2000 and the end of 2001.

        Stock Based Compensation.    Stock based compensation expense was zero in 2001 compared to $8.8 million for the year ended December 31, 2000. The stock based compensation in 2000 is a charge associated with the valuation of management's interest in our predecessor as a result of the Yorktown investment in May 2000.

        Impairments.    Impairment expense was $2.9 million for the year ended December 31, 2001 compared to zero for the prior year. The impairment charge was recorded to reduce the carrying value of the Jonesville plant and related intangible assets to fair value in accordance with SFAS 121. See "—Critical Accounting Policies—Impairment of Long-Lived Assets" below.

        (Profit) Loss on Energy Trading Contracts.    The loss on energy trading contracts for the year ended December 31, 2001 was $3.7 million compared to a profit of $1.9 million for the prior year. The loss on energy trading contracts in 2001 includes $5.7 million associated with the write-down of the estimated realizable value of our receivable from Enron North America Corp., a subsidiary of Enron Corp., at December 31, 2001. On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp., each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Enron North America failed to make timely payment of approximately $3.9 million for physical delivery of gas in 2001. This amount remained outstanding as of December 31, 2001. Additionally, we had entered into natural gas hedging and physical delivery contracts with Enron North America. According to the terms of the contracts, Enron North America is liable to us for the

27

mark-to-market value of all contracts outstanding on the date we exercised our termination right under the contracts, which totaled approximately $4.6 million and which has been recorded as a receivable from Enron North America. We have accounted for these contracts as energy trading contracts whereby changes in fair value of the fixed price purchase commitments are recognized in earnings.

        We had offsets to the above amounts totaling approximately $0.3 million, resulting in a net $8.2 million receivable from Enron North America at December 31, 2001. Due to the uncertainty of future collections, a charge and related allowance for 70% of the net receivable, or $5.7 million, was recorded at December 31, 2001. Further adjustments to the Enron receivable will be recognized in earnings when management believes recovery of the asset is assured or additional reserves are warranted.

        The receivable from Enron was not contributed to our new partnership.

        Partially offsetting the Enron-related loss in the 2001 period are the realized margins on delivered volumes in the producer services "off-system" gas marketing operations. In 2001, the realized margins from the producer services operations were approximately $1.9 million, compared to approximately $1.8 million in 2000.

        Depreciation and Amortization.    Depreciation and amortization expense was $6.1 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.3 million, or 119%. The increase in depreciation and amortization is primarily related to acquisitions of new assets, which resulted in additional depreciation and amortization expense as follows:

•

ownership of the Arkoma system for the full year in 2001 as compared to only five months in 2000 increased depreciation and amortization expense by $0.5 million;



•

ownership of the Gulf Coast system for the full year in 2001 as compared to four months in 2000 increased depreciation and amortization expense by $0.6 million; and



•

the acquisition of the CCNG assets in May 2001 increased depreciation and amortization expense by $1.3 million.

        In addition, the accounting associated with the Yorktown investment in May 2000 resulted in an increase in depreciation and amortization for subsequent periods. Therefore, depreciation and amortization expense for the first four months of 2000 is approximately $0.4 million lower than if the investment had occurred at the beginning of 2000.

        Interest Expense.    Interest expense was $2.3 million for the year ended December 31, 2001 compared to $0.6 million for the year ended December 31, 2000, an increase of $1.6 million, or 270%. The increase was principally caused by increases in average outstanding borrowings as a result of the CCNG acquisition and the acquisition and refurbishment of treating plants. In addition, borrowings relative to the Arkoma and Gulf Coast assets were outstanding for the full year in 2001 as compared to only a part of 2000.

        Net Income (Loss).    Net loss for the year ended December 31, 2001 was ($3.9) million compared to ($6.1) million for the year ended December 31, 2000. Gross margin improved from $8.9 million in 2000 to $24.2 million in 2001, an improvement of $15.3 million, or 171%, largely as a result of acquisition-related growth as discussed above. This improvement was partially offset by increases in recurring cash charges for operating expenses, general and administrative expenses, and interest expense totaling $9.8 million, non-cash charges for depreciation and amortization of $3.3 million, and the loss on energy trading contracts and impairments totaling $8.5 million.

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Critical Accounting Policies

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

        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

29

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 contracts are reported as profit or loss on energy trading contracts 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 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 (used) in operating activities was $20.0 million, ($8.3) million, and $15.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash provided by operating activities in 2002 improved principally due to higher margins ($8.6 million) offset by higher cash expenses ($5.6 million), the loss on energy contracts related to Enron in 2001 ($5.7 million), and fund flows for working capital accounts. Net cash used in operating activities during the year ended December 31, 2001 was $23.4 million lower than the prior year principally attributable to higher margins ($15.3 million), offset by higher cash expenses ($9.8 million), the loss on energy trading contracts related to Enron ($5.7 million), and fund flows for working capital accounts.

        Net cash used in investing activities was $33.2 million, $52.5 million and $28.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash used in investing activities during all periods was primarily related to acquisition and internal growth projects. Net cash used in investing activities during each of the years ended December 31, 2002, 2001 and 2000 was primarily to fund

30

acquisitions of the Vanderbilt system, the CCNG assets, buying and refurbishing and installing treating plants, the Arkoma and Gulf Coast systems, the Millennium acquisition, and internal growth capital projects.

        Net cash provided by financing activities was $14.2 million, $42.6 million and $36.6 million for the years ended December 31, 2002, 2001 and 2000, respectively. Financing activities primarily represent equity investments and borrowings from banks to fund our acquisitions and other investments discussed above, and funding or refunding of the company's working capital needs.

        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. In addition, we are currently studying the possibility of expanding the capacity of our Gregory processing plant by 60,000 Mcf/d at an estimated cost ranging from $7.1 million to $9.2 million.

        We believe that cash generated from operations will be sufficient to meet our minimum quarterly distributions and anticipated maintenance capital expenditures through December 31, 2003. We expect to fund our growth capital expenditures from cash provided by operations and, to the extent necessary, from the proceeds of borrowings under the revolving credit facility discussed below and the issuance of additional common units. We may not be able to issue additional units or may not be able to issue such units on favorable terms primarily as a result of market conditions for our securities. Our ability to pay distributions to our unitholders 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.

        Total Contractual Cash Obligations.    A summary of our total contractual cash obligations as of December 31, 2002, is as follows:

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

Description of Credit Facility

        In connection with the closing of our initial public offering, we entered into a new $67.5 million credit facility, consisting of the following two facilities:

•

a senior secured revolving acquisition facility in the aggregate principal amount of $47.5 million; and



•

a senior secured revolving working capital facility in the aggregate principal amount of $20.0 million.

        The acquisition facility is used to finance the acquisition and development of gas gathering, treating and processing facilities, as well as general partnership purposes. At December 31, 2002, we had $21.8 million outstanding under the acquisition facility, leaving approximately $25.7 million available for future borrowings. The acquisition facility will convert into a term loan on April 30, 2004, and we will be required to make eleven quarterly payments equal to five percent of the outstanding borrowings. The first such payment will be due in July 2004. The term loan will mature in April 2007, at which time it will terminate and all outstanding amounts shall be due and payable. Prior to April 30, 2004, amounts borrowed and repaid under the acquisition credit facility may be reborrowed.

        The working capital facility is used for ongoing working capital needs, letters of credit, distributions and general partnership purposes, including future acquisitions and expansions. At December 31, 2002, we had $13.1 million of letters of credit issued under the working capital facility, leaving approximately $6.9 million available for future issuances of letters of credit, or up to $5.0 million of cash borrowings. The aggregate amount of borrowings under the working capital 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 $5.0 million sublimit for cash borrowings. This facility will mature in April 2004, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital facility may be reborrowed. We are required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.

        Our obligations under the 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. The credit facility is guaranteed by certain of our subsidiaries. We may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs).

        Indebtedness under the acquisition facility and the working capital facility bear interest at our option at the administrative agent's reference rate plus 0.125% to 1.375% or LIBOR plus 1.625% to 2.875%. The applicable margin will vary 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. At December 31, 2002, our weighted average interest rate was 4.02%. We will incur quarterly commitment fees based on the unused amount of the credit facilities.

        In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement. The Partnership has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses

32

relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged.

        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 credit facility contains various covenants limiting 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; or



•

engage in transactions with affiliates.

        The credit facility also contains covenants requiring us to maintain:

•

a maximum ratio of total funded debt to consolidated EBITDA (each as defined in the credit facility), measured quarterly on a rolling four quarter basis, of 4.00 to 1 through June 30, 2003, declining to 3.75 to 1 beginning September 30, 2003, 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 $55 million.

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

•

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



•

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



•

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



•

certain ERISA events involving us or our subsidiaries;



•

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.

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, 2000, 2001, or 2002. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

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Environmental

        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 Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations, requiring business combinations entered into after June 30, 2001, to be accounted for using the purchase method of accounting. Specifically identifiable intangible assets acquired, other than goodwill, will be amortized over their estimated useful economic life. This pronouncement had no effect on our predecessor's financial position or results of operations.

        In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS No. 142 requires that we identify reporting units for purposes of assessing potential future impairments of goodwill, reassess the useful lives of other existing recognized intangible assets, and cease amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with the guidance in SFAS No. 142. This statement is required to be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS No. 142 required us to complete a transitional goodwill impairment test within six months from the date of adoption and reassess the useful lives of other intangible assets within the first interim quarter after adoption. Our predecessor had $4,873,000 recorded for goodwill, net of accumulated amortization at December 31, 2001 and recorded goodwill amortization expense of $292,000 for the year ended December 31, 2001. The only impact of adopting SFAS No. 142 on our financial statements was the discontinuance of the amortization of goodwill.

        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 is required to be adopted by us beginning on January 1, 2003. We do not presently have any significant asset retirement obligations, and accordingly, the adoption of SFAS No. 143 is not expected to have a significant impact on our results of operations or financial condition.

        In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 addresses financial accounting and reporting for impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to be Disposed Of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. This statement also amends ARB No. 51, Consolidated Financial Statements, to eliminate the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. See the impact of the adoption of SFAS No. 144 at Note 2 (c) of the Notes to Consolidated Financial Statements of our predecessor.

        In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than when the entity commits to an exit plan. This standard is effective for all exit or disposal activities which are initiated after December 31, 2002. We

34

do not anticipate that the adoption of SFAS No. 146 will have any impact on our financial position or results of operations.

        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 June 2002, the Emerging Issues Task Force (EITF) reached consensus on certain issues in EITF Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts. Consensus was reached on two issues: 1) that gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the statement of operations, and 2) that entities should disclose the types of contracts that are accounted for as energy trading contracts along with a variety of other data regarding values, sensitivity to changes in estimates, maturity dates, and other factors. We early adopted this consensus in the second quarter of 2002 and all comparative financial statements were reclassified to report gains or losses on energy trading contracts net in the statements of operations. In October 2002, the EITF reached a consensus to rescind EITF 98-10. Accordingly, energy related contracts that are not accounted for pursuant to SFAS No. 133 should be accounted for as executory contracts and carried on an accrual basis, not fair value. The consensus should be applied prospectively to all new energy trading contracts entered into after October 25, 2002 and to all contracts that existed on October 25, 2002, in periods beginning after December 15, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principles. The rescission of EITF 98-10 did not have any significant effect on our financial position or results of operations.

        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 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 ending after December 15, 2002. The adoption of the statement is not expected to have a material effect on the Partnership's financial statements when adopted.

        In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities. FIN No. 46 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 June 15, 2003. The Partnership is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN No. 46 will not have an impact on our financial statements.

35

Risk Factors

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

        Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. We cannot guarantee that we will be able to pay the minimum quarterly distributions of $0.50 per common unit in each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

        Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

        From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        The success of our business strategy to increase and optimize throughput on our pipeline and gathering assets is dependent upon our securing additional supplies of natural gas.

        Our operating results are dependent upon securing additional supplies of natural gas from increased production by natural gas production companies in the Texas Gulf Coast. The ability of producers to increase production is dependent on natural gas prices, the exploration and production budgets of the production companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters beyond our control. There can be no assurance that production of natural gas will rise to sufficient levels to maintain or increase the throughput on our pipeline and gathering assets.

        Our operations are dependent upon demand for natural gas by industry and utilities in the Texas Gulf Coast. Any decrease in this demand could adversely affect our business.

        We face intense competition in our gathering and marketing activities. Our competitors include other natural gas pipelines and their marketing affiliates, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of natural gas. See Item 1. "Business—Competition."

        We are exposed to the credit risk of our customers in the ordinary course of our gathering and marketing activities. In our gathering and marketing operations, we take title to the natural gas and resell the gas to our various market outlets, which include a variety of utility, refining, petrochemical, metals production and other industrial consumers, as well as to the pipeline companies. A significant failure to pay by one of our major customers would adversely affect our ability to maintain distributions.

        In conjunction with the Yorktown investment in July, 2000, we allocated $14.2 million in value to intangible assets and $4.6 million to goodwill. At December 31, 2002, $5.3 million and $4.9 million of intangible assets and goodwill, respectively, remain as assets in the consolidated balance sheets. We

36

evaluate these assets for impairment at least annually. Changes in the Company's business could result in impairments of these assets.

Disclosure Regarding Forward-Looking Statements

        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), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "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.

        These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number or risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

        Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Risk Factors," and elsewhere in this report.

        You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. You should be aware that the occurrence of any of the events described in "Risk Factors" and elsewhere in this prospectus could substantially harm our business, results of operations and financial condition and that, upon the occurrence of any of these events, the trading price of our common units could decline.

        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 6.2% 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 44% of the gas we purchased during the year ended December 31, 2002. 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, 2002, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have changed our processing margin by $446,738. Changes in natural gas prices indirectly may impact our profitability since prices

37

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.

        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, 2002, we had $21.8 million of indebtedness outstanding. 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 for a period of two years. The impact of a 100 basis point increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $218,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our debt outstanding at December 31, 2002.

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.

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.

        Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders, 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.

        Three members of the board of directors of our general partner, namely Messrs. Haden, Murchison 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 unitholders.

        The Audit Committee of our general partner, comprised of Messrs. Wells and Haden, provides oversight for the external financial reporting of the Partnership. The Compensation Committee of our general partner, comprised of Messrs. Lubar and Murchison, oversees compensation decisions for the officers of the General Partner as well as the compensation plans described below.

        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.

*

Indicates chairman of committee.

        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

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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—Midstream 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 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—Treating Division, 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, Senior Vice President—Business 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, Senior 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—Engineering and Operations, 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

40

Gas Processors and General Electric. Mr. Scott holds a B.S. degree in Mechanical Engineering from Oklahoma State University.

        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 Carbon Energy Corporation, 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 Resources Inc., Camden Resources, Inc., ESI Energy Services Inc., Ellora Energy Inc., and Dernick Resources Inc. 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

41

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.

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 2002 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 first 12 months following our initial public offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will 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."

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. 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.

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Summary Compensation Table

(1)

Reflects the aggregate salary paid by the registrant and its predecessor for fiscal 2002. 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 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 have received equity-based awards from our general partner. No awards have vested to date under our Long-Term Incentive Plan. 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 $201,500, $171,064, $171,064, $160,875, $160,875 and $134,304 for Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, respectively.

        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.

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        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 unitholder 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 or membership on the board of directors terminates for any reason, 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 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.

        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

44

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 unitholders.

Option Grants

        The following table contains information about unit option grants to the named executive officers in 2002 (except as indicated):

Option Grants in Last Fiscal Year

(1)

The total number of options granted to employees in 2002 used to calculate these percentages includes 195,000 common units underlying options granted upon the closing of the Company's initial public offering. The options vest at a rate of ¹/3 per year beginning December 17, 2003.

(2)

All options granted were under the Crosstex Energy, LLC Long-Term Incentive Plan

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 2002, 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, 2002.

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

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. Directors are also reimbursed for related out-of-pocket expenses. Each committee chairman receives $2,500 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. Directors are also entitled to a one-time grant of 10,000 options at an exercise price of $20.

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.

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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 March 4, 2003 held by:

•

each person who then will beneficially own 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


•

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

*

Less than 1%.

(1)

The address of each person listed above is 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, except for Crosstex Energy Holdings Inc. and Bryan H. Lawrence which is 410 Park Avenue, New York, New York 10022.

(2)

Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott each hold an ownership interest in Crosstex Energy Holdings Inc. as indicated in the following table.

(3)

Grants of options to purchase a total of 195,000 common units were made upon the closing of the initial public offering to employees of Crosstex Energy GP, LLC, including the named executive officers. See "—Long-Term Incentive Plan."

(4)

These units are held in a trust for the benefit of the Mr. Haden's children. Mr. Haden and his spouse are trustees of the trust.

(5)

Bryan H. Lawrence is a member and a manager of the general partner of both Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. Both of these limited partnerships own an interest in Crosstex Energy Holdings Inc. as indicated in the following table.

(6)

Sheldon B. Lubar is a general partner of Lubar Nominees, and Lubar Nominees holds an ownership interest in Crosstex Energy Holdings Inc. as indicated in the following table.

(7)

These units are held by Murchison Capital Partners, L.P. Mr. Murchison is the President of the Murchison Management Corp., which serves as the general partner of Murchison Capital Partners, L.P.

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        The following table shows the beneficial ownership of Crosstex Energy Holdings Inc. as of March 4, 2003. Crosstex Energy Holdings Inc. owns Crosstex Energy GP, LLC and, together with Crosstex Energy GP, LLC, our general partner and, as reflected above, common units and subordinated units.

*

Less than 1%.

(1)

Unless otherwise indicated, the address of each person listed above is 2501 Cedar Springs, Suite 600, Dallas, Texas 75201.

(2)

The address for Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. is 410 Park Avenue, New York, New York 10022.

(3)

Sheldon B. Lubar is a general partner of Lubar Nominees, and may be deemed to beneficially own the shares held by Lubar Nominees.

(4)

Ownership percentage for such individual or group includes shares issuable pursuant to stock options which are presently exercisable or exercisable within 60 days.

(5)

Bryan H. Lawrence is a member and a manager of the general partner of both Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P.

Beneficial Ownership of General Partner Interest

        Crosstex Energy GP, L.P. owns all of our 2% general partner interest and all of our incentive distribution rights. Crosstex Energy GP, L.P. is owned 0.001% by its general partner, Crosstex Energy GP, LLC and 99.999%; by its sole limited partner, Crosstex Energy Holdings Inc.

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Equity Compensation Plan Information

(1)

Our general partner has adopted and maintains a Long Term Incentive Plan for our officers, employees and directors. See Item 11. "Executive Compensation—Long-Term Incentive Plan." The LTIP contemplates awards of up to 233,000 restricted units and 467,000 unit options.

(2)

The current strike price for all outstanding options under the plan is $20.00 per unit.

(3)

Consisting of 233,000 restricted units and 272,000 unit options.

Item 13. Certain Relationships and Related Transactions

Our General Partner

        Our operations and activities are managed by, and our officers are employed by, the operating partnership. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf. For the first 12 months following our initial public offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will 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.

        Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.450 per unit, 23% of the amounts we distribute in excess of $0.50 per unit and 48% of amounts we distribute in excess of $0.675 per unit.

Relationship with Crosstex Energy Holdings Inc.

        General.    Crosstex Energy Holdings Inc. owns 333,000 common units and 4,667,000 subordinated units representing an aggregate 68.5% limited partnership interest in us. Our general partner owns a 2% general partner interest in us and the incentive distribution rights. Our general partner's ability, as general partner, to manage and operate Crosstex Energy, L.P. and Crosstex Energy Holdings' ownership of an aggregate 68.5% limited partner interest in us effectively gives our general partner the ability to veto some of our actions and to control our management.

        Omnibus Agreement.    Concurrent with the closing of our initial public offering, we entered into an agreement with Crosstex Energy Holdings Inc., Crosstex Energy GP, LLC and our general partner which will govern potential competition among us and the other parties to the agreement. Crosstex Energy Holdings Inc. agreed, and caused its controlled affiliates to agree, for so long as management, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. and its affiliates, or any

49

combination thereof, control our general partner, not to engage in the business of gathering, transmitting, treating, processing, storing and marketing of natural gas and the transportation, fractionation, storing and marketing of NGLs unless it first offers us the opportunity to engage in this activity or acquire this business, and the board of directors of Crosstex Energy GP, LLC, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. In addition, Crosstex Energy Holdings Inc. has the ability to purchase a business that has a competing natural gas gathering, transmitting, treating, processing and producer services business if the competing business does not represent the majority in value of the business to be acquired and Crosstex Energy Holdings Inc. offers us the opportunity to purchase the competing operations following their acquisition. The noncompetition restrictions in the omnibus agreement do not apply to the assets retained and business conducted by Crosstex Energy Holdings Inc. at the closing of our initial public offering. Except as provided above, Crosstex Energy Holdings Inc. and its controlled affiliates are not prohibited from engaging in activities in which they compete directly with us. In addition, Yorktown Energy Partners IV, L.P., Yorktown Energy Partners V, L.P. and any affiliated Yorktown funds are not prohibited from owning or engaging in businesses which compete with us.

Initial Public Offering and Concurrent Transactions

        On December 17, 2002, the Partnership completed an initial public offering of 2,300,000 common units representing limited partner interests and received therefrom net proceeds of approximately $40.2 million. Concurrently with the closing of the initial public offering, certain transactions were consummated in connection with the formation of the Partnership. These transactions involved the transfer to us by Crosstex Energy Holdings Inc. of substantially all the assets and liabilities of Crosstex Energy Services, Ltd. (the predecessor of our operating partnership Crosstex Energy Services, L.P.) in exchange for and the right to receive $2.5 million from the proceeds of the initial public offering and the issuance of 333,000 common units and 4,667,000 subordinated units (which are held by Crosstex Energy Holdings Inc.) and the incentive distribution rights and a 2% general partner interest in the Partnership (which are held by Crosstex Energy GP, L.P.). In addition, certain assets and liabilities of Crosstex Energy Services, Ltd. were not contributed to the Partnership, but, instead, were transferred to a subsidiary of Crosstex Energy Holdings Inc. These include receivables associated with the Enron Corp. bankruptcy discussed above under "Item 7. Management's Discussion and Analysis of Financial Position and Results of Operations—Results of Operations—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts." Also, the Jonesville processing plant, which was largely inactive since the beginning of 2001, and the recently acquired Clarkson plant were not contributed to the Partnership, but, instead were transferred to a subsidiary of Crosstex Energy Holdings Inc.

Related Party Transactions

        Camden Resources, Inc.    We treat gas for, and purchase gas from, Camden Resources, Inc. Yorktown Energy Partners IV, L.P. has made equity investments in both Camden and Crosstex Energy Holdings Inc. The gas treating and gas purchase agreements we have entered into with Camden are standard industry agreements containing terms substantially similar to those contained in our agreements with other third parties. During the year ended December 31, 2002, we purchased natural gas from Camden Resources, Inc. in the amount of approximately $10.1 million and received approximately $399,000 in treating fees from Camden Resources, Inc.

        Crosstex Pipeline Company.    We indirectly own general and limited partner interests in Crosstex Pipeline Partners, L.P. that represent a 28% economic interest. We have entered into various transactions with Crosstex Pipeline Partners, and we believe that the terms of these transactions are comparable to those that we could have negotiated with unrelated third parties. During the year ended December 31, 2002, our predecessor: (1) purchased natural gas from Crosstex Pipeline Partners in the amount of approximately $3.4 million and paid Crosstex Pipeline Partners approximately $27,000 for transportation of natural gas, (2) received a management fee from Crosstex Pipeline Partners in the

50

amount of approximately $125,000 and (3) received approximately $90,000 in distributions from Crosstex Pipeline Partners;

Item 14. Controls And Procedures

        An evaluation of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures as of March 21, 2003 was carried out by the General Partner under the supervision and with the participation of the General Partner's management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures have been designed and are being operated in a manner that provides reasonable assurance that the information required to be disclosed by the Partnership in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. A controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within an entity have been detected. Subsequent to the date of the most recent evaluation of the Partnership's internal controls, there were no significant changes in the Partnership's internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

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PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)

Financial Statements and Schedules



(1)

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



(2)

No schedules are required.



(3)

Exhibits

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