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TABLE OF CONTENTS

As filed with the Securities and Exchange Commission on August 7, 2002

Registration Statement No. 333-            

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Crosstex Energy, L.P.
(Exact name of registrant as specified in its charter)

Crosstex Energy GP, L.P.
2501 Cedar Springs
Suite 600
Dallas, Texas 75201
(214) 953-9500
(Name, address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)

William W. Davis
Crosstex Energy GP, L.P.
2501 Cedar Springs, Suite 600
Dallas, Texas 75201
(214) 953-9500
(Name, address, including zip code, and telephone number,
including area code, of agent for service)

Copies to:

Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this Registration Statement.

        If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. / /

        If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / /

        If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / /

        If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / /

        If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. / /

CALCULATION OF REGISTRATION FEE

(1)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

        The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

Subject to completion, dated August 7, 2002

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS

2,000,000 Common Units

[Crosstex Logo]

Crosstex Energy, L.P.

Representing Limited Partner Interests

        We are offering 2,000,000 common units representing limited partner interests. This is the initial public offering of our common units. We expect the initial public offering price to be between $19.00 and $21.00 per common unit. Holders of common units are entitled to receive distributions of available cash of $0.50 per quarter, or $2.00 per unit on an annualized basis, before any distributions are paid on our subordinated units, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We will apply for quotation of our common units on the Nasdaq National Market under the symbol "XTEX".

Investing in our common units involves risk.
See "Risk Factors" beginning on page 14.

        These risks include the following:

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We may not have sufficient cash to pay the minimum quarterly distribution each quarter.

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We must continually compete for natural gas supplies, and any decrease in our supplies of natural gas could reduce our ability to make distributions to our unitholders.

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

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

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Due to our lack of asset diversification, adverse developments in our gathering, transmission, treating, processing and producer services businesses would reduce our ability to make distributions to our unitholders.

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Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of our unitholders.

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

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

•

You will experience immediate and substantial dilution in net tangible book value of $11.45 per common unit.

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You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

PRICE $        PER COMMON UNIT

        We have granted the underwriters a 30-day option to purchase up to an additional 300,000 common units to cover over-allotments. The underwriters expect to deliver the common units to purchasers on or about                            , 2002.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

A.G. Edwards & Sons, Inc.

Raymond James

RBC Capital Markets

Prospectus dated                            , 2002

[Map showing location of gathering and transmission
systems and processing and treating facilities]

TABLE OF CONTENTS

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PROSPECTUS SUMMARY

        The summary highlights selected information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit and (2) that the underwriters' over-allotment option is not exercised. You should read "Summary of Risk Factors" beginning on page 3 and "Risk Factors" beginning on page 14 for more information about important factors that you should consider before buying common units. We have included a "Glossary of Terms" as Appendix C that defines many of the terms we use in this prospectus.

        References in this prospectus to "Crosstex Energy, L.P.," "we," "ours," "us," or like terms when used in the present tense or prospectively refer to Crosstex Energy, L.P. and its operating subsidiaries. Crosstex Energy, L.P. is the issuer of securities in this offering. References to "our predecessor," "we," "ours," "us," or like terms when used in a historical context refer to Crosstex Energy Services, Ltd. Substantially all of the assets of Crosstex Energy Services, Ltd. will be transferred to us at the closing of the offering.

Crosstex Energy, L.P.

Overview

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

        Our major assets include over 1,500 miles of natural gas gathering and transmission pipelines, one natural gas processing plant connected to our gathering system with a total NGL production capacity of 210,000 gallons per day 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 plant removes NGLs from a natural gas stream and 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 grown rapidly since the inception of our various predecessors in 1992 through a combination of acquisitions and the construction of new assets. Our operating income plus depreciation and amortization expense, which we refer to as EBITDA, has increased from $0.8 million in 1997 to $4.3 million in 2001. Our EBITDA was $2.4 million for the three months ended March 31, 2002. EBITDA for 2001 and the three months ended March 31, 2002 has been reduced by non-cash impairment charges of $2.9 million and $3.2 million, respectively.

        We have two operating divisions, the Midstream division, which consists of our natural gas gathering, transmission, processing, marketing and producer services operations, and the Treating division, which provides natural gas treating for the removal of carbon dioxide and other contaminants.

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Midstream Division

        Our primary Midstream assets are four major systems along the Texas Gulf Coast and one in eastern Oklahoma, which in the aggregate consist of approximately 1,500 miles of gathering and transmission pipelines, and a natural gas processing plant connected to one of these gathering systems. For the three months ended March 31, 2002, we gathered and transported approximately 387,000 Mcf/d of natural gas.

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Gulf Coast System. Our Gulf Coast system consists of approximately 484 miles of gathering and transmission pipelines that run northeast along the Gulf Coast from Refugio County in south Texas to Fort Bend County near Houston, Texas. Natural gas is supplied to the system from approximately 87 receipt points, which involve production from one or more wells, and six treating and processing plant tailgates and marketed to a number of utility and industrial consumers. This system interconnects with multiple third-party pipelines offering both supply and sales sources. Our Gulf Coast system has a capacity of 200,000 Mcf/d and average throughput was approximately 98,834 Mcf/d for the three months ended March 31, 2002.



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Corpus Christi System. Our Corpus Christi system consists of approximately 295 miles of gathering and transmission pipelines that extend from supply points in south Texas to utility and industrial markets in Corpus Christi, Texas. Natural gas is supplied to this system from approximately 15 receipt points, 12 treating and processing plants and third-party gathering systems and pipelines. Our Corpus Christi system has a capacity of 350,000 Mcf/d and average throughput was approximately 139,968 Mcf/d for the three months ended March 31, 2002.



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Gregory Gathering System. Our Gregory gathering system consists of approximately 297 miles of gathering pipelines located primarily in the Corpus Christi Bay area that supply liquids-rich natural gas to our Gregory processing plant. Natural gas is supplied to our Gregory gathering system from approximately 70 receipt points. Our Gregory gathering system has a capacity of 200,000 Mcf/d and average throughput was approximately 84,855 Mcf/d for the three months ended March 31, 2002.



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Gregory Processing Plant. Our Gregory processing plant removes NGLs from the natural gas supplied by our Gregory gathering system and fractionates or separates them into marketable products for sale to third parties. Our Gregory processing plant has an inlet capacity of approximately 85,000 Mcf/d and average throughput was approximately 77,200 Mcf/d for the three months ended March 31, 2002.



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Arkoma Gathering System. Our Arkoma gathering system consists of approximately 100 miles of gathering pipelines located in eastern Oklahoma. This low-pressure system gathers gas from approximately 142 wells to three compressor stations for discharge to a mainline transmission pipeline. Our Arkoma gathering system has a capacity of 20,000 Mcf/d and average throughout was approximately 10,454 Mcf/d for the three months ended March 31, 2002.

        In our producer services operations, we purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 80 independent producers. 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.

Treating Division

        We believe that we are the second largest independent provider of natural gas treating services in the United States. As of March 31, 2002, we owned 49 mobile, skid-mounted treating plants of various sizes, 20 of which were operated by our personnel, nine of which were operated by producers, one of which was operated by a joint venture partner and 19 of which were held in inventory. The treating

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

Summary of Risk Factors

        An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of common units. Those risks are described under the caption "Risk Factors" and include:

Risks Inherent in Our Business

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



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The assumptions underlying the financial forecast in Appendix E are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.



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We must continually compete for natural gas supplies, and any decrease in our supplies of natural gas could reduce our ability to make distributions to our unitholders.



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



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



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We are exposed to the credit risk of our customers, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.



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



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



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If we do not make acquisitions on economically acceptable terms, our future growth may be limited.



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Our rapid growth may cause difficulties integrating new operations, and we have a limited combined operating history.



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



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



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Our use of derivative financial instruments has in the past and could in the future result in financial losses or reduce our income.



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Due to our lack of asset diversification, adverse developments in our gathering, transmission, treating, processing and producer services businesses would reduce our ability to make distributions to our unitholders.



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

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Risks Inherent in an Investment in Us

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Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of our unitholders.



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



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



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The control of our general partner may be transferred to a third party, and that third party could replace our current management team, in each case without unitholder consent.



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



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

Tax Risks to Our Unitholders

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The IRS could treat us as a corporation for tax purposes which would substantially reduce the cash available for distribution to our unitholders.



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A successful IRS contest of the federal income tax positions we take may adversely affect the market for common units, and the costs of any contest will be borne by us and therefore indirectly by our unitholders and our general partner.



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You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.



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

Competitive Strengths

        We believe that we are well positioned to compete in the natural gas gathering, transmission, treating, processing and producer services businesses. Our competitive strengths include:

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Strategic position in the Texas Gulf Coast. Our operations are currently focused in the Texas Gulf Coast, with our Gregory processing plant and 83% of our total gathering and transmission pipeline miles located in this region. The Texas Gulf Coast is characterized by consistently high levels of drilling activity, which provide us with significant opportunities to access newly developed gas supplies. We believe our significant presence and asset base in the Texas Gulf Coast generally provides us with a competitive advantage in capturing new supplies of natural gas and markets for natural gas because of our resulting lower costs of handling newly connected gas and delivering it to market. Our existing position in the Texas Gulf Coast region is especially advantageous because constructing a significant new pipeline system in this region would be extremely difficult due to population density and regulatory constraints.

Our treating operations, with 19 treating plants of varying sizes available in inventory, provides us with an advantageous position to compete for new treating business in the Texas Gulf Coast because natural gas produced from certain deeper formations in the Texas Gulf Coast is high in carbon dioxide. We believe we have the largest inventory of available treating plants in our markets, which we believe gives us a competitive advantage for new treating business since we can often have a plant in service quicker than our competitors.

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Asset base with available capacity. By aggressively marketing directly to producers and end users and adding connections to new customers, we believe we have the opportunity to leverage our existing asset base in order to fully utilize the capacity of our systems and thereby significantly increase throughput and cash flows. Since our systems either have unused capacity or can be expanded at minimal additional costs, transporting additional volumes of natural gas through our systems should provide incremental operating income.



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Range of services. We offer a full range of midstream services to natural gas producers, including gathering, transmission, treating, processing and marketing. In addition, as a component of our producer services business, we purchase natural gas for sale to others and in doing so provide risk management opportunities to natural gas producers. We believe this full range of services gives us advantages in competing for new business because we can provide substantially all the services a producer requires to get its production of natural gas to market as compared to our competitors who often do not provide a full range of services. In addition, we provide a full range of services to natural gas buyers including an aggregated supply of natural gas, load balancing and price risk management, which allows buyers to find a significant volume of natural gas that meets their requirements without having to negotiate with multiple producers.



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Proven acquisition expertise. Since January 2000, we have acquired and integrated 10 operations with an aggregate purchase price of approximately $60.6 million. Our management team's significant industry contacts have enabled us to become aware of, and gain access to, strategic acquisition opportunities. We intend to use our experience and reputation in strategically acquiring assets to continue to grow through accretive acquisitions, focusing on opportunities in which we see potential to improve throughput volumes and cash flows.



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Flexible financial structure. Upon the completion of this offering, we expect to enter into a new $    million credit facility under which we would have a borrowing base of approximately $    million and availability of $            million. We believe the available capacity under this new credit facility combined with our ability to access the capital markets should provide us with a flexible financial structure that will facilitate our strategic expansion and acquisition strategy.



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Experienced and motivated management. Our management team's extensive experience and contacts within the midstream industry provides a strong foundation for managing and enhancing our operations, for accessing strategic acquisition opportunities and for constructing new assets. Our senior management team, which will indirectly own            subordinated and            common units upon completion of this offering and approximately            % of our general partner, has an average of over 20 years of industry experience primarily with the type of assets and in the markets we currently operate.

Business Strategy

        Our strategy is to increase distributable cash flow per unit by improving the profitability of our existing systems through increasing volumes and reducing costs, focusing on accretive acquisitions and pursuing system construction and expansion opportunities. Key elements of our strategy include the following:

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Improving existing system profitability. After we acquire or construct a new system, we begin an aggressive effort to market directly to both producers and end users in order to connect new supplies of natural gas, increase volumes 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.



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Pursuing accretive acquisitions. We intend to use our substantial acquisition and integration experience to continue to make strategic acquisitions of midstream assets that offer the

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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.

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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.

PARTNERSHIP STRUCTURE AND MANAGEMENT

        Our operations will be conducted through, and our operating assets will be owned by, our operating partnership, Crosstex Energy Services, Ltd., and its subsidiaries. Our general partner, Crosstex Energy GP, L.P., has sole responsibility for conducting our business and for managing our operations. The senior executives who currently manage our business will continue to manage and operate the business as the senior executives of Crosstex Energy GP, LLC, the general partner of our general partner. Our general partner will not receive any management fee or other compensation in connection with its management of our business but will be entitled to reimbursement for all direct and indirect expenses incurred on our behalf. Upon completion of this offering and the related transactions:

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Crosstex Energy Holdings Inc. will own a 100% interest in Crosstex Energy GP, LLC;



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Officers of Crosstex Energy GP, LLC will collectively own    % of Crosstex Energy Holdings Inc.;



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Crosstex Energy Holdings Inc. will own a 99.999% limited partner interest in our general partner and Crosstex Energy GP, LLC will own a 0.001% general partner interest in our general partner;



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Crosstex Energy GP, L.P., our general partner, will own the 2% general partner interest in us as well as the incentive distribution rights;



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Crosstex Energy Holdings Inc. and its affiliates will own 175,000 common units and 4,350,000 subordinated units, totaling an aggregate 68.0% limited partner interest in us;



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the public unitholders will own, in the aggregate, a 30.0% limited partner interest in us represented by the 2,000,000 common units;



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we will, directly and indirectly, own all of the ownership interest in the operating partnership; and



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the operating partnership and our subsidiary, Crosstex Energy Services GP, LLC, will own 100% of the various subsidiary companies.

        Our principal executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our phone number is (214) 953-9500.

        The chart on the following page depicts the organization and ownership of us and our operating partnership after giving effect to the offering and the related formation transactions.

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Ownership percentages do not sum to 100% due to rounding.

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THE OFFERING

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        The following table sets forth summary historical financial and operating data of our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated and the summary pro forma financial and operating data of Crosstex Energy, L.P. as of and for the year ended December 31, 2001 and the three months ended March 31, 2002. The summary historical financial data for the years ended December 31, 1999 and 2001 and for the four months ended April 30, 2000 and for the eight months ended December 31, 2000 are derived from the audited financial statements of Crosstex Energy Services, Ltd. and its predecessor. The summary historical financial data for the three months ended March 31, 2001 and 2002 are derived from the unaudited financial statements of Crosstex Energy Services, Ltd. and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. 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 summary pro forma financial and operating data of Crosstex Energy, L.P. reflect the consolidated historical operating results of Crosstex Energy Services, Ltd., as adjusted for the offering and the related transactions. The summary pro forma financial data are derived from the unaudited pro forma financial statements. The pro forma balance sheet assumes that the offering and related transactions occurred on March 31, 2002. The pro forma statements of operations assume that the offering and related transactions occurred on January 1, 2001. For a description of all of the assumptions used in preparing the summary pro forma financial data, you should read the notes to the pro forma financial statements for Crosstex Energy, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.

        We define EBITDA as operating income (loss) plus depreciation and amortization expense. EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other entities, and other entities may not calculate EBITDA in the same manner as we do.

        Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them.

        We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included in this prospectus. The table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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(1)

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)

EBITDA for the year ended December 31, 2001 and the three months ended March 31, 2002 has been reduced by non-cash impairment charges of $2.9 million and $3.2 million, respectively.

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SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES

        Crosstex Energy GP, L.P., our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary" duty. However, because Crosstex Energy GP, L.P. is indirectly owned by Crosstex Energy Holdings Inc., the officers and directors of Crosstex Energy GP, LLC, who manage and operate our general partner, have fiduciary duties to manage the business of our general partner in a manner beneficial to Crosstex Energy Holdings Inc. The officers and directors of Crosstex Energy GP, LLC have significant relationships with, and responsibilities to, Crosstex Energy Holdings Inc. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary responsibilities of our general partner, please read "Conflicts of Interest and Fiduciary Responsibilities."

        Our general partner is permitted to resolve conflicts of interest by considering the interests of all the parties involved. Therefore, our general partner can consider the interests of its affiliates if a conflict of interest arises between the common unitholders and our general partner and its affiliates. Our general partner will have a conflicts committee, consisting of at least two independent members of its board of directors, that will be available to review matters involving conflicts of interest.

        Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

        We will enter into an agreement with Crosstex Energy Holdings Inc. whereby it will generally agree not to engage in the business of gathering, transmitting, treating, processing and marketing of natural gas. In addition, our general partner will not receive any management fee or other compensation for its management of us but our general partner and its affiliates will be reimbursed for general and administrative expenses incurred on our behalf. For the twelve months following this 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. For a more detailed discussion of these agreements, please read "Certain Relationships and Related Transactions."

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RISK FACTORS

        Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in the common units.

        If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Inherent in Our Business

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

        We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay our general partner's fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things;

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



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the level of our processing and treating operations;



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the fees we charge and the margins we realize for our services;



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the price of natural gas;



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the relationship between natural gas and NGL prices; and



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our level of operating costs.

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

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the level of capital expenditures we make;



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the cost of acquisitions, if any;



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our debt service requirements;



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fluctuations in our working capital needs;



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restrictions on distributions contained in our credit facility;



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our ability to make working capital borrowings under our revolving credit facility to pay distributions;



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prevailing economic conditions; and



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the amount, if any, of cash reserves established by our general partner in its discretion for the proper conduct of our business.

        Because of these factors, we may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Furthermore, you should also be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be

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affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

        The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after the offering is approximately $13.3 million. If we had completed the transactions contemplated in this prospectus on January 1, 2001, pro forma available cash from operating surplus generated during the year ended December 31, 2001 would have been approximately $5.1 million. If we had completed the transactions contemplated in this prospectus on January 1, 2002, pro forma available cash from operating surplus generated during the three months ended March 31, 2002 would have been approximately $2.2 million. The amount of pro forma cash available for distribution during 2001 and the first three months of 2002 would have been sufficient to allow us to pay the minimum quarterly distribution on all the common units and 7.6% and 47.7%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2001 and for the three months ended March 31, 2002, please read "Cash Available for Distribution" and Appendix D.

The assumptions underlying the financial forecast in Appendix E are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The financial forecast set forth in Appendix E includes our forecast of statements of operations for the twelve months ending September 30, 2003. The financial forecast has been prepared by management and we have not received an opinion or report on it from any independent accountants. In addition, Appendix E includes a calculation of available cash from operating surplus based on the financial forecast. The assumptions underlying the financial forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we may not be able to pay the full minimum quarterly distributions or any amount on the common units or subordinated units, in which event the market price of the common units may decline materially.

We must continually compete for natural gas supplies, and any decrease in our supplies of natural gas could reduce our ability to make distributions to our unitholders.

        If we are unable to maintain or increase the throughput on our systems by accessing new natural gas supplies to offset the natural decline in reserves, our business and financial results could be materially adversely affected. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

        In order to maintain or increase throughput levels in our natural gas gathering systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies. Our industry is highly competitive, and we cannot assure you that we will be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near our gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production for a prolonged period along the Texas Gulf Coast, as a result of depressed commodity prices or otherwise, likely would have a

15

material adverse effect on our results of operations and financial position. See "Business—Natural Gas Supply" for more information on our supplies of natural gas.

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

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

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

        We are subject to significant risks due to fluctuations in commodity prices. These risks are based upon two components of our business: (1) the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; and (2) certain processing contracts for our Gregory system whereby we are exposed to natural gas and NGL commodity price risks.

        The margins we realize from purchasing and selling a portion of the natural gas that we transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of the index price. For the three months ended March 31, 2002, we purchased approximately 7% of our gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact on our results of operations.

        A portion of our profitability is affected by the relationship between natural gas and NGL prices. For a component of our Gregory system volumes, we purchase natural gas, process natural gas and extract NGLs, and then sell the processed natural gas and NGLs. Since we extract Btus from the gas stream in the form of the liquids or consume it as fuel during processing, we reduce the Btu content of the natural gas. Accordingly, our margins under these arrangements can be negatively affected in periods in which the value of natural gas is high relative to the value of NGLs. For example, a decrease of $.01 per gallon in the price of NGLs and an increase of $.10 per MMBtu in the average price of natural gas for the three months ended March 31, 2002 would have resulted in decreases in processing margins of approximately $132,000. For the three months ended March 31, 2002, we purchased approximately 52% of the natural gas volumes on our Gregory system under such contracts. In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue.

        We attempt to execute all natural gas purchases and sales substantially concurrently, but we may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or deliver in excess of contracted volumes, or a consumer could purchase less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

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

•

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



•

the level of domestic oil and natural gas production;

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•

the availability of imported oil and natural gas;



•

actions taken by foreign oil and gas producing nations;



•

the availability of local, intrastate and interstate transportation systems;



•

the availability and marketing of competitive fuels;



•

the impact of energy conservation efforts; and



•

the extent of governmental regulation and taxation.

We are exposed to the credit risk of our customers, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

        Risks of nonpayment and nonperformance by our customers are a major concern in our business. Several of our customers have been receiving heightened scrutiny from the financial markets in light of the collapse of Enron Corp. We are subject to risks of loss resulting from nonpayment or nonperformance by these and other customers. We recognized a charge of $5.7 million in 2001 for sales contracts with Enron. These contracts related to our producer services operations in which we purchased and sold natural gas that did not move on our gathering and transmission systems. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

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

        The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve.

        For the three months ended March 31, 2002, approximately 52% of our sales of gas which are transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

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

        We currently derive a significant portion of our revenues from contracts with a subsidiary of Kinder Morgan Inc., and we have entered into gas sales contracts with Entex Gas Resources, the local gas distribution company for the city of Houston, which commenced July 1, 2002. To the extent that these and other customers may reduce volumes of natural gas purchased under existing contracts, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers. Sales to the subsidiary of Kinder Morgan accounted for 22.3% of our revenues during the first three months of 2002 and 11.9% of our revenues during 2001. Our primary contract with Kinder Morgan expires in March 2006 and our contract with Entex expires in July 2004.

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If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

        Our future growth will depend principally on our ability to make acquisitions at attractive prices. We cannot assure you that we will be able to identify attractive acquisition candidates or that we will be able to acquire businesses on economically acceptable terms. We may not be able to acquire additional businesses for various reasons, including the following:

•

we may be unable to use cash or access capital to pay for additional acquisitions without adversely affecting our ability to make cash distributions to our unitholders;



•

we may not be able to use common units as an acquisition currency;



•

we may not be able to obtain debt financing;



•

we may not able to obtain regulatory approvals, including those under federal and state antitrust laws; and



•

competition for acquisition targets may increase and cause the cost of completing acquisitions to rise.

Our rapid growth may cause difficulties integrating new operations, and we have a limited combined operating history.

        Since January 2000, we have made 10 acquisitions with an aggregate purchase price of approximately $60.6 million that have significantly increased our asset base. Unexpected costs or challenges may arise whenever different operations are combined. Any acquisition involves potential integration risks, including:

•

the inability to integrate the operations of recently acquired assets;



•

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



•

strain on human resources, placing added emphasis on the ability to attract and retain management and employees; and



•

a significant increase in our indebtedness.

        If we are unable to successfully integrate the companies, businesses or assets that we have acquired or in the future may acquire, our revenues may decline and we could, therefore, experience a material adverse effect on our business, financial condition or results of operations.

        Because we have grown rapidly, we have a limited operating history for most of our operations to which you may look to evaluate our performance. As a result, the historical and pro forma information may not give you an accurate indication of what our actual results would have been if the acquisitions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.

        One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties

18

inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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

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

•

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



•

inadvertent damage from construction and farm equipment;



•

leaks of natural gas, NGLs and other hydrocarbons; and



•

fires and explosions.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our operations are concentrated in the Texas Gulf Coast, and a natural disaster or other hazard affecting this region could have a material adverse effect on our operations. We are not fully insured against all risks incident to our business. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and future war or risk of war may adversely impact our results of operations.

        The impact that the terrorist attacks of September 11, 2001 may have on the energy industry in general, and on us in particular, is not known at this time. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror.

        The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to the September 11 attacks have made certain types of insurance more difficult for us to obtain. Our insurance policies now generally exclude acts of terrorism as compared to our policies prior to September 11, 2001. Such insurance is not available at what we believe to be acceptable pricing levels. A lower level of economic activity could also result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

The highly competitive nature of our industry could cause us to lose customers and future business opportunities, thereby reducing our revenues and limiting our future profitability.

        Competition is intense in many of our markets. The principal areas of competition include obtaining gas supplies and the transportation and marketing of natural gas and NGLs. Our competitors include major integrated oil companies, interstate and intrastate pipelines and natural gas gatherers and processors. Some of our competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do. We compete with integrated companies that have greater access to natural gas supplies and are less susceptible to fluctuations in price or volume, and some of our competitors that have greater financial resources may have an advantage in competing for acquisitions or other new business opportunities. Our competitors may have the ability to pay higher

19

prices for natural gas supplies and to sell natural gas and NGLs at more aggressive pricing than we do, which could hurt our profitability.

Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.

        As of March 31, 2002, our total long-term indebtedness was approximately $54.5 million. Upon completion of the offering, we expect our total outstanding long-term indebtedness to be approximately $            million, including approximately $            million under our credit facility and $            million of other indebtedness. Our payments of principal and interest on the indebtedness will reduce the cash available for distribution on the units. We will be prohibited by our credit facility from making cash distributions during an event of default under any of our indebtedness. Furthermore, our leverage and various limitations in the credit facility may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

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

        While the Federal Energy Regulatory Commission, or FERC, does not regulate any of our operations, directly or indirectly, it influences certain aspects of our business and the market for our products. As a raw natural gas gatherer we generally are exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects our business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

        Some of our intrastate natural gas transmission pipelines are subject to regulation as a common carrier and as a gas utility by the Texas Railroad Commission, or TRRC. The TRRC's jurisdiction extends to both rates and pipeline safety. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. Such complaints have been rare, and the regulation of intrastate natural gas pipeline rates has been relatively limited. Should a complaint be filed or should regulation become more active, our business may be adversely affected.

        Other state and local regulations also affect our business. We are subject to ratable take and common purchaser statutes in the states where we operate. Ratable take statues generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Oklahoma and Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

        The states in which we conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968. The "rural gathering exemption" under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The "rural gathering exemption,"

20

however, may be restricted in the future, and it does not apply to our natural gas transmission pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements. We do not believe that these heightened pipeline safety requirements will affect us in a way that materially differs from the way they affect other natural gas transporters, gatherers, processors, and marketers. See "Business—Regulation."

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

        Many of the operations and activities of our gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from our facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

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

        Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability.

Our use of derivative financial instruments has in the past and could in the future result in financial losses or reduce our income.

        We use over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions, and we use futures and option contracts traded on the New York Mercantile Exchange. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. We could, however, incur financial losses or fail to recognize the full value of a market opportunity as a result of volatility in the market values of the underlying commodities or if one of our counterparties fails to perform under a contract. For additional information about our risk management activities, including our use of derivative financial instruments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk."

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Due to our lack of asset diversification, adverse developments in our gathering, transmission, treating, processing and producer services businesses would reduce our ability to make distributions to our unitholders.

        We rely exclusively on the revenues generated from our gathering, transmission, treating, processing and producer services businesses. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

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

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

Risks Inherent in an Investment in Us

Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of our unitholders.

        Following this offering, Crosstex Energy Holdings Inc. will indirectly own an aggregate limited partner interest of approximately 68% in us and will own and control our general partner. Conflicts of interest may arise in the future between Crosstex Energy Holdings Inc. and its affiliates, including our general partner, on the one hand, and our partnership or any of the unitholders, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations:

Conflicts Relating to Control:

•

our partnership agreement limits our general partner's liability and reduces its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner. As a result of purchasing units, our unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law;



•

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



•

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



•

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



•

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



•

in some instances our general partner may cause us to borrow funds from affiliates of the general partner or from third parties in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or hasten the expiration of the subordination period; and

22

•

our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.

Conflicts Relating to Costs:

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partnership interests and reserves, each of which can affect the amount of cash that is distributed to our unitholders;



•

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



•

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

Please read "Conflicts of Interest and Fiduciary Responsibilities."

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

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

        Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 66²/3% of the outstanding units voting together as a single class. Because the general partner and its affiliates will control approximately 69.3% of all the units, the general partner currently cannot be removed without the consent of the general partner and its affiliates. Also, if the general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal without cause would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units which would otherwise have continued until we had met certain distribution and performance tests.

        Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include, in most cases, charges of poor management of the business, so the removal of the general partner because of the unitholders' dissatisfaction with the general partner's performance in managing our partnership will most likely result in the termination of the subordination period.

        In addition, unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner,

23

cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

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

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

        Prior to making any distributions on the units, we will reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make distributions to you. Our general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner. See "Management—Reimbursement of Expenses of the General Partner."

The control of our general partner may be transferred to a third party, and that third party could replace our current management team, in each case without unitholder consent.

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

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

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

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

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

You will experience immediate and substantial dilution in net tangible book value of $11.45 per common unit.

        The assumed initial public offering price of $20.00 per unit exceeds pro forma net tangible book value of $8.55 per unit. Based on the assumed initial public offering price, you will incur immediate

24

and substantial dilution of $11.45 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with generally accepted accounting principles. Please read "Dilution."

We may issue additional common units without your approval, which would dilute your ownership interests.

        During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,087,500 additional common units (1,237,500 additional common units if the underwriters' over-allotment option is exercised in full). Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

•

the issuance of common units in connection with acquisitions that increase cash flow from operations per unit on a pro forma basis;



•

the conversion of subordinated units into common units;



•

the conversion of units of equal rank with the common units into common units under some circumstances;



•

the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;



•

issuances of common units under our long-term incentive plan; or



•

issuances of common units to repay indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the debt's retirement.

        The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our unitholders' proportionate ownership interest in us will decrease;



•

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



•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;



•

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



•

the market price of the common units may decline.

        After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

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

        If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, our general partner and its affiliates will own 8.0% of the common units. At the end of the subordination period,

25

assuming no additional issuances of common units, our general partner and its affiliates will own approximately 69.3% of the common units. For additional information about the call right, please read "The Partnership Agreement—Limited Call Right."

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

        As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the "control" of our business. Our general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Please read "The Partnership Agreement—Limited Liability" for a discussion of the implications of the limitations on liability to a unitholder.

Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

        Prior to the offering, there has been no public market for the common units. After the offering, there will be only 2,000,000 publicly-traded units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

Restrictions in our credit facility could limit our ability to make distributions to our unitholders.

        We will enter into a new, $            million credit facility in connection with the closing of this offering. The credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to our unitholders. The credit facility also contains covenants requiring us to maintain certain financial ratios, such as EBITDA to interest expense and total debt to EBITDA, and minimum net worth. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the credit facility. In addition, the credit facility prohibits us from borrowing more than $    million in any four-quarter period to make distributions to unitholders.

Tax Risks to Our Unitholders

        You are urged to read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to our unitholders.

        The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.

        If we were treated as a corporation for federal income tax purposes, we would pay tax on our income at corporate rates of up to 35% (under current law) and we would probably pay state income taxes as well. In addition, distributions to you would generally be taxed again to you as corporate distributions and no income, gains, losses, or deductions would flow through to you. Because a tax

26

would be imposed upon us as a corporation, the cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you and thus would likely result in a material reduction in the value of the common units.

        A change in current law or a change in our business could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be decreased to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the costs of any contest will be borne by us and therefore indirectly by our unitholders and our general partner.

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

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

        You will be required to pay federal income taxes and, in some cases, state, local, and foreign income taxes on your share of our taxable income even if you do not receive cash distributions from us. You may not receive cash distributions equal to your share of our taxable income or even the tax liability that results from that income.

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

        If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, will likely be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

        Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated

27

business income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company or mutual fund. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income.

We will register as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

        We intend to register with the IRS as a "tax shelter." We will advise you of our tax shelter registration number once that number has been assigned. The tax laws require that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

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

        Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

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

        In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state, local and foreign income tax returns and pay state, local and foreign income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We will initially own property and conduct business in Texas, Oklahoma, Louisiana and New Mexico. Oklahoma, Louisiana and New Mexico impose an income tax, generally. Texas does not impose a state income tax on individuals, but does impose a franchise tax on limited liability companies and corporations in certain circumstances. We may do business or own property in other states or foreign countries in the future. It is your responsibility to file all federal, state, local, and foreign tax returns. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.

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USE OF PROCEEDS

        We expect to receive net proceeds of approximately $34.7 million (or $40.3 million if the underwriters exercise their over-allotment option) from the sale of the 2,000,000 common units offered by this prospectus, after deducting underwriting discounts and estimated offering expenses. We intend to use $         million of the net proceeds of this offering to repay outstanding borrowings under our new bank credit facility, which replaced our predecessor's credit facility. The remainder of the net proceeds will be used for working capital and other general corporate purposes.

        As of March 31, 2002, total borrowings under our predecessor's bank credit facility were approximately $54.5 million and had a weighted average interest rate of 4.61%. Our predecessor incurred all of the debt under its bank credit facility for acquisitions and for working capital purposes. Our new credit facility has a maturity date of            .

        We will use any net proceeds from the exercise of the over-allotment option to repay borrowings under our credit facility.

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CAPITALIZATION

        The following table shows:

•

our historical cash and cash equivalents and capitalization as of March 31, 2002; and



•

our pro forma cash and cash equivalents and capitalization as of March 31, 2002, adjusted to reflect the formation transactions, the offering of the common units and the application of the net proceeds we receive in the offering as described under "Use of Proceeds."

        We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2002 after giving effect to the offering of common units and the related transactions, our net tangible book value was $56.9 million, or $8.55 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

(1)

Determined by dividing the number of units (175,000 common units, 4,350,000 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 133,163 units, calculated by taking 2% of the number that results from dividing 6,525,000, the total number of units outstanding, by 98%, the percentage of all partnership interests represented by such units) to be issued to affiliates of the general partner for their contribution of assets and liabilities to Crosstex Energy, L.P. into the net tangible book value of the contributed assets and liabilities.

(2)

Determined by dividing the total number of units (2,175,000 common units, 4,350,000 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 133,163 units) to be outstanding after the offering into the pro forma net tangible book value of Crosstex Energy, L.P., after giving effect to the application of the net proceeds of the offering.

        The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner, its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

(1)

Upon the consummation of the transactions contemplated by this prospectus, Crosstex Energy Holdings Inc. and its affiliates will own an aggregate of 175,000 common units and 4,350,000 subordinated units and our general partner will own a 2% general partner interest in Crosstex Energy, L.P. having a dilutive effect equivalent to 133,163 units.

(2)

The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with generally accepted accounting principles.

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

        General.    Within approximately 45 days after the end of each quarter, beginning with the quarter ending December 31, 2002, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through December 31, 2002 based on the actual length of the period.

        Definition of Available Cash.    We define available cash in the glossary, and it generally means, for each fiscal quarter:

•

all cash on hand at the end of the quarter;



•

less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:



•

provide for the proper conduct of our business;



•

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



•

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



•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

        Minimum Quarterly Distribution.    Common units are entitled to receive distributions from operating surplus of $.50 per quarter, or $2.00 on an annualized basis, before any distributions are paid on our subordinated units. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility.

        Contractual Restrictions on our Ability to Distribute Available Cash.    Our ability to distribute available cash is contractually restricted by the terms of the credit facility we will enter into in connection with the closing of this offering. We expect that the credit facility will contain covenants requiring us to maintain certain financial ratios, such as EBITDA to interest expense and total debt to EBITDA, and a minimum net worth. We will be prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the credit facility.

Operating Surplus and Capital Surplus

        General.    All cash distributed to unitholders will be characterized either as "operating surplus" or "capital surplus." We distribute available cash from operating surplus differently than available cash from capital surplus.

        Definition of Operating Surplus.    We define operating surplus in the glossary, and for any period it generally means:

•

our cash balance on the closing date of this offering; plus



•

$8.4 million (as described below); plus

32

•

all of our cash receipts after the closing of this offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus



•

working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less



•

all of our operating expenditures after the closing of this offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures, and less



•

the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

        As reflected above, our definition of operating surplus includes $8.4 million in addition to our cash balance on the closing date of this offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $8.4 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus.

        Definition of Capital Surplus.    We also define capital surplus in the glossary, and it will generally be generated only by:

•

borrowings other than working capital borrowings;



•

sales of debt and equity securities; and



•

sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

        Characterization of Cash Distributions.    We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. While we do not currently anticipate that we will make any distributions from capital surplus in the near term, we may determine that the sale or disposition of an asset or business owned or acquired by us may be beneficial to our unitholders. If we distribute to you the equity we own in a subsidiary or the proceeds from the sale of one of our businesses, such a distribution would be characterized as a distribution from capital surplus.

Subordination Period

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

33

        Definition of Subordination Period.    We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after September 30, 2007 that each of the following tests are met:

•

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



•

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



•

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

        Early Conversion of Subordinated Units.    Before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:

•

September 30, 2005 with respect to 25% of the subordinated units; and



•

September 30, 2006 with respect to 25% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following three tests are met:

•

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



•

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



•

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

However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.

        Definition of Adjusted Operating Surplus.    We define "adjusted operating surplus" in the glossary, and for any period it generally means:

•

operating surplus generated with respect to that period; less



•

any net increase in working capital borrowings with respect to that period; less



•

any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus



•

any net decrease in working capital borrowings with respect to that period; and plus



•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

        Adjusted Operating Surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

34

        Effect of Expiration of the Subordination Period.    Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately convert into one common unit on a one-for-one basis;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

First, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;



•

Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;



•

Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Distributions of Available Cash from Operating Surplus After the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

First, 98% to all unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Incentive Distribution Rights

        Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

        If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

35

•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

•

First, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner until each unitholder receives a total of $0.625 per unit for that quarter (the "first target distribution");



•

Second, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the "second target distribution"); and



•

Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner.

        In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Target Amount of Quarterly Distribution

        The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders, our general partner and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our unitholders, our general partner and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions from Capital Surplus

        How Distributions from Capital Surplus will be Made.    We will make distributions of available cash from capital surplus in the following manner:

•

First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

36

•

Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and



•

Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

        Effect of a Distribution from Capital Surplus.    The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of incentive distribution rights and 2% to our general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units we will proportionately adjust:

•

the minimum quarterly distribution;



•

target distribution levels;



•

unrecovered initial unit price;



•

the number of common units issuable during the subordination period without a unitholder vote; and



•

the number of common units into which a subordinated unit is convertible.

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

37

Distributions of Cash upon Liquidation

        General.    If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

        Manner of Adjustments for Gain.    The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•

First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:



(1)

the unrecovered initial unit price;



(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and



(3)

any unpaid arrearages in payment of the minimum quarterly distribution on that common unit;




•

Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until the capital account for each subordinated unit is equal to the sum of:



(1)

the unrecovered initial unit price; and



(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;




•

Fourth, 85% to all unitholders, pro rata, 13% to the holders of incentive distribution rights, pro rata, and 2% to our general partner until we allocate under this paragraph an amount per unit equal to:



(1)

the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less



(2)

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

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•

Fifth, 75% to all unitholders, pro rata, 23% to the holders of incentive distribution rights, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:



(1)

the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less



(2)

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence;




•

Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to our the general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

        Manner of Adjustments for Losses.    Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•

First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the subordinated unitholders have been reduced to zero;



•

Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the common unitholders have been reduced to zero; and



•

Thereafter, 100% to our general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

        Adjustments to Capital Accounts.    We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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CASH AVAILABLE FOR DISTRIBUTION

        We intend to pay each quarter, to the extent we have sufficient available cash from operating surplus, the minimum quarterly distribution of $0.50 per unit, or $2.00 per year, on all the common units and subordinated units. Available cash for any quarter will consist generally of all cash on hand at the end of that quarter, plus working capital borrowings after the end of the quarter, as adjusted for reserves. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus working capital borrowings after the end of the quarter, plus $8.4 million. The definitions of available cash and operating surplus are in the glossary.

        The amounts of available cash from operating surplus needed to pay the minimum quarterly distribution for one quarter and for four quarters on the common units and the subordinated units and to pay the related distribution on the general partner interest to be outstanding immediately after this offering are approximately:

Pro forma available cash from operating surplus from prior periods would not have been sufficient to pay the minimum quarterly distribution on all units.

        If we had completed the transactions contemplated in this prospectus on January 1, 2001, pro forma available cash from operating surplus generated during 2001 would have been approximately $5.1 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 7.6% of the minimum quarterly distribution on the subordinated units for that period. If we had completed the transactions contemplated in this prospectus on January 1, 2002, pro forma available cash from operating surplus generated during the three months ended March 31, 2002 would have been approximately $2.2 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 47.7% of the minimum quarterly distribution on the subordinated units for that period.

        We derived the amounts of pro forma available cash from operating surplus shown above from our pro forma financial statements in the manner described in Appendix D. The pro forma adjustments are based upon currently available information and specific estimates and assumptions. The pro forma financial statements do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, available cash from operating surplus as defined in the partnership agreement is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should only view the amount of pro forma available cash from operating surplus as a general indication of the amount of available cash from operating surplus that we might have generated had we been formed in earlier periods. A more complete explanation of the pro forma adjustments can be found in the Notes to Our Unaudited Pro Forma Financial Statements.

        Furthermore, pro forma available cash from operating surplus has not been reduced to reflect incremental general and administrative expenses, such as cost of tax return preparation, accounting

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support services, annual and quarterly reports to unitholders, investor relations and registrar and transfer agent fees, that we expect to incur at an annual rate of approximately $650,000.

We believe we will have sufficient available cash from operating surplus following the offering to pay the minimum quarterly distribution on all units through September 30, 2003.

        We believe that, following completion of the offering, we will have sufficient available cash from operating surplus to allow us to make the full minimum quarterly distribution on all outstanding common and subordinated units for each quarter through September 30, 2003. Our belief is based on our financial forecast in Appendix E.

        You should read the notes and the other information in Appendix E carefully for a discussion of the material assumptions underlying the financial forecast. The financial forecast presents, to the best of our knowledge and belief, the expected results of our operations for the forecast period. The financial forecast is based on certain assumptions and reflects our judgment of expected business and industry conditions. The assumptions disclosed herein are those that we believe are significant to the financial forecast. We believe our actual results of operations will approximate those reflected in the financial forecast; however, because events and circumstances frequently do not occur as expected, we can give you no assurance that the forecast results will be achieved. There will likely be differences between the forecast and the actual results and those differences may be material. If the forecast is not achieved, we may not be able to pay the full minimum quarterly distribution or any amount on the common units. The financial forecast has been prepared by management and we have not received an opinion or report on it from any independent accountants.

        When considering the financial forecast, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors—Risks Inherent in Our Business" and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in Appendix E.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        The following table sets forth selected historical financial and operating data of our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated and the summary pro forma financial and operating data of Crosstex Energy, L.P. as of and for the year ended December 31, 2001 and the three months ended March 31, 2002. The selected historical financial data for the years ended December 31, 1997, 1998, 1999 and 2001 and for the four months ended April 30, 2000 and the eight months ended December 31, 2000 are derived from the audited financial statements of Crosstex Energy Services, Ltd. and its predecessor. The selected historical financial data for the three months ended March 31, 2001 and 2002 are derived from the unaudited financial statements of Crosstex Energy Services, Ltd. and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. 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 selected 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 selected pro forma financial and operating data of Crosstex Energy, L.P. reflect the consolidated historical operating results of Crosstex Energy Services, Ltd., as adjusted for the offering and the related transactions. The summary pro forma financial data are derived from the unaudited pro forma financial statements. The pro forma balance sheet assumes that the offering and related transactions occurred on March 31, 2002. The pro forma statements of operations assume that the offering and related transactions occurred on January 1, 2001. For a description of all of the assumptions used in preparing the summary pro forma financial data, you should read the notes to the pro forma financial statements for Crosstex Energy, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.

        We define EBITDA as operating income (loss) plus depreciation and amortization expense. EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other entities, and other entities may not calculate EBITDA in the same manner as we do.

        Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them.

        We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included in this prospectus. The table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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