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TABLE OF CONTENTS 2
TABLE OF CONTENTS

As filed with the Securities and Exchange Commission on August 15, 2003

Registration Statement No. 333-106927

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 1
to
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. o

        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. o

        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. o

        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. o

        If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. 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 this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to such Section 8(a), may determine.

Subject to completion, dated August 15, 2003

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 document is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS

1,500,000 Common Units

Crosstex Energy, L.P.

Representing Limited Partner Interests

        We are offering 1,500,000 common units representing limited partner interests. Our common units are traded on the Nasdaq National Market under the symbol "XTEX." On August 14, 2003, the last reported sale price of our common units on the Nasdaq National Market was $36.55 per common unit.

Investing in our common units involves risk.
See "Risk Factors" beginning on page 16.

        These risks include the following:

•

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



•

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.



•

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



•

If we are unable to integrate our recent acquisitions or if we do not continue to make acquisitions on economically acceptable terms, our future financial performance may be limited.



•

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



•

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.



•

Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner will be entitled to be reimbursed for all direct and indirect expenses it incurs on our behalf, which may be substantial and will reduce our ability to make distributions to unitholders.



•

Crosstex Energy Holdings Inc. controls our general partner and will own a 56% limited partner interest in us after the offering. 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.



•

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.



•

Our common units have a limited trading history and a limited trading volume compared to other units representing limited partner interests.



•

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 225,000 common units to cover over-allotments. The underwriters expect to deliver the common units to purchasers on or about                , 2003.

        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.

RBC Capital Markets

Raymond James

Prospectus dated                , 2003

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

TABLE OF CONTENTS

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iii

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PROSPECTUS SUMMARY

        The summary highlights selected information contained elsewhere in this prospectus. 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 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 16 for more information about important factors that you should consider before buying common units. We have included a "Glossary of Terms" as Appendix A 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 or for historical periods since December 2002 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" or to "we," "ours," "us," or like terms for historical periods prior to December 2002 refer to Crosstex Energy Services, Ltd. Substantially all of the assets of Crosstex Energy Services, Ltd. were transferred to us at the closing of our initial public offering in December 2002.

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.

        We have grown rapidly since the inception of our various predecessors in 1992 through a combination of acquisitions and the construction of new assets. Since January 2000, we have acquired and integrated 13 operations with an aggregate purchase price of approximately $142.3 million, including our recent $67.3 million acquisition of assets from Duke Energy Field Services, L.P., which we refer to in this prospectus as DEFS. Our net income increased to $2.0 million for the year ended December 31, 2002, compared to a net loss of $0.5 million for the year ended December 31, 1998. Our net income was $5.8 million for the six months ended June 30, 2003. Our gross margin increased to $32.7 million for the year ended December 31, 2002, compared to $2.2 million for the year ended December 31, 1998. Our gross margin was $23.9 million for the six months ended June 30, 2003.

        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. Our primary Midstream assets include systems located along the Texas Gulf Coast and in south-central Mississippi, and, in the aggregate, consist of approximately 2,500 miles of gathering and transmission pipelines, and three natural gas processing plants. After giving pro forma effect to our recent acquisition of assets from DEFS, for the year ended December 31, 2002 and the six months ended June 30, 2003, we would have gathered and transported approximately 501,233 MMBtu/d and 603,160 MMBtu/d of natural gas, respectively. 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 50 independent producers. Our treating plants remove carbon dioxide and hydrogen sulfide from

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natural gas before it is delivered into transportation systems to ensure that the natural gas meets pipeline quality specifications.

Recent Developments

Recent Acquisitions

        Duke Energy Field Services.    In June 2003, we acquired various midstream assets located in Mississippi, Texas, Alabama and Louisiana from DEFS for $67.3 million in cash. The principal assets we acquired were the AIM pipeline system, a 638-mile natural gas gathering and transmission system in Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. In addition, we acquired the Conroe gas plant and gathering system north of Houston, the Black Warrior gathering pipeline system in Alabama and two small gathering systems in Louisiana. This acquisition has provided us with a new core area for growth in south-central Mississippi, expanded our presence in West Texas, increased the total miles of our pipelines from 1,700 to 2,500 and enabled us to enter the business of carbon dioxide separation. In addition, the acquisition should increase the stability of our cash flow as operating profits from the AIM pipeline system are generated through purchasing, gathering, transporting and reselling natural gas which generates margins not affected by commodity prices, and a majority of the income we receive from the Seminole gas plant is based on fixed fees for carbon dioxide separation and sulfur removal. Average throughput on the AIM pipeline system at the time of acquisition was approximately 81,195 MMBtu/d.

        Vanderbilt System.    In December 2002, we acquired the Vanderbilt system from a subsidiary of Devon Energy Corporation for $12.0 million. The Vanderbilt system consists of approximately 200 miles of gathering pipeline located near our Gulf Coast system. The system's gathering pipeline ranges in diameter from four to 14 inches and has a capacity of 130,000 Mcf/d. Average throughput on the system was approximately 40,850 MMBtu/d for the six months ended June 30, 2003. Gathered natural gas currently flows to the Formosa Hydrocarbons processing plant at Point Comfort, Texas.

        Will-O-Mills.    In December 2002, we consolidated our ownership of the Will-O-Mills treating plant by purchasing the remaining 50% operating interest we did not own for $2.2 million. The consolidation of the Will-O-Mills interest enabled us to negotiate the closure of another plant in the area and transfer those volumes to Will-O-Mills, resulting in an approximate 30% increase in cash flow from the plant. In addition, we are able to utilize Will-O-Mills direct labor capacity to more efficiently manage other company assets in the area.

Recent Expansion and Construction

        Gregory Expansion.    We are nearing completion of an expansion of our Gregory processing plant. The expansion will increase the plant capacity from approximately 90,000 Mcf/d to 150,000 Mcf/d and will cost approximately $8.0 million. We expect to complete this expansion in August 2003. In addition, we have significantly reduced our exposure to commodity prices by renegotiating a number of our commodity-based contracts, where revenues were subject to fluctuating commodity prices, to fee-based contracts.

        Barnett Shale.    In February 2003, we formed a joint venture, in which we own a 50% interest, to construct a gathering system in an area of the Barnett Shale gas formation, near Denton, Texas, at an initial cost of $3.0 million. The system consists of approximately 14 miles of gathering pipelines and the system is expected to have a capacity of approximately 35,000 Mcf/d.

        Hallmark Lateral.    In June 2002, we acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line, which we refer to as the Hallmark Lateral. We constructed an

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addition to this transmission line to connect our Gulf Coast and Corpus Christi systems. This connection lets us transport gas between our two systems, which reduces our dependence on third-party suppliers and allows us to move gas supplies to more favorable markets and enhance our margins. In November 2002, we completed construction of the interconnect between the Hallmark Lateral and the Florida Gas Transmission mainline. With this connection, we began selling gas into the Florida markets and we sold approximately 46,020 MMBtu/d into Florida for the six months ended June 30, 2003.

Other Developments

        Distribution Increase.    On July 10, 2003, we announced that the board of directors of our general partner has authorized for the quarter ended September 30, 2003 an increase in our quarterly distribution to $0.70 per unit, or $2.80 per unit on an annualized basis, from $0.55 per unit. This distribution will be payable on or about November 14, 2003. The board of directors of our general partner declared a quarterly distribution of $0.55 for the quarter ended June 30, 2003. This distribution was paid on August 15, 2003 to holders of record on July 31, 2003.

        Bank Credit Facility.    In June 2003, our operating partnership, Crosstex Energy Services, L.P., entered into a new $100.0 million senior secured credit facility, which matures in June 2006, consisting of a $70.0 million acquisition facility and a $30.0 million working capital and letter of credit facility. After giving effect to this offering, we expect our operating partnership to have approximately $64.1 million of the acquisition facility available for future borrowings.

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

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

•

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 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.



•

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



•

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



•

If we are unable to integrate our recent acquisitions, or if we do not continue to make acquisitions on economically acceptable terms, our future financial performance may be limited.



•

We have limited control over the development of certain assets because we are not the operator.

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We expect to encounter significant competition in any new geographic areas into which we seek to expand and our ability to enter such markets may be limited.



•

We are exposed to the credit risk of our customers and counterparties, and a general 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.



•

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



•

We have a limited combined operating history.



•

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



•

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.



•

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

Risks Inherent in an Investment in Us

•

Crosstex Energy Holdings Inc. controls our general partner and will own a 56% limited partner interest in us upon completion of the offering. 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.



•

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.



•

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



•

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.



•

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 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 common units have a limited trading history and a limited trading volume compared to other stocks and units representing limited partner interests.

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.



•

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.



•

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



•

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

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:

•

Strategic position in the Texas Gulf Coast and Mississippi. Our Gregory and Conroe processing plants and approximately 51% of our total gathering and transmission pipeline miles are located in the Texas Gulf Coast. 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. The acquisition of the AIM pipeline system, located in south-central Mississippi, allowed us to establish a new core area outside of our strategic position in the Texas Gulf Coast.



•

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 more fully utilize the capacity of our systems and thereby significantly increase throughput and cash flows. Since our pipeline and gathering systems, including those acquired from DEFS, operated at an overall utilization of approximately 47% of capacity in the first six months of 2003, transporting additional volumes of natural gas through our systems should provide incremental operating income. We believe our inventory of 12 treating plants gives us a competitive advantage for capturing new treating business since we can often have a plant in service faster than our competitors.



•

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.



•

Proven acquisition and development expertise. Since January 2000, we have acquired and integrated 13 operations with an aggregate purchase price of approximately $142.3 million, including our recent $67.3 million acquisition of assets from DEFS which enabled us to expand our operations into Mississippi and Alabama. 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 through marketing and new construction and expansion projects. We have invested in excess of $50.0 million in our construction and expansion projects from January 2000 through June 2003.

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•

Flexible financial structure. Our operating partnership has a $70.0 million acquisition facility, approximately $64.1 million of which will be available upon the closing of this offering, and a $30.0 million working capital and letter of credit facility. In addition, our operating partnership has a $50.0 million master shelf facility for senior secured notes. Our operating partnership has issued $40.0 million of senior secured notes under this facility, and any future issuances will be subject to negotiation of certain terms, including pricing. We believe the available capacity under the bank credit facility and the senior secured notes, combined with our ability to access the capital markets, should provide us with a flexible financial structure that will facilitate our expansion and acquisition strategy.



•

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 indirectly owns approximately 49,000 common units, approximately 686,000 subordinated units and approximately 15% of our general partner, has an average of over 20 years of industry experience primarily with the type of assets and the markets in which we currently operate. Please read "Management—Directors and Executive Officers of Crosstex Energy GP, LLC" for a discussion of the experience of our executive officers.

Business Strategy

        Our strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas, improving the profitability of our assets by increasing their utilization while controlling costs and pursuing new construction or expansion opportunities in our core operating areas. Key elements of our strategy include the following:

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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 opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired assets. We pursue acquisitions that we believe will add to our 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.



•

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 more 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.



•

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 are conducted through, and our operating assets are owned by, our operating partnership, Crosstex Energy Services, L.P., and its subsidiaries. Upon completion of this offering:

•

the public unitholders will own a 42.3% limited partner interest in us, represented by 3,800,000 common units;

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•

Crosstex Energy Holdings Inc. will own a 55.7% limited partner interest in us, represented by 333,000 common units and 4,667,000 subordinated units; and



•

our general partner will continue to own a 2% general partner interest in us and all of our incentive distribution rights.

        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.

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(1)

For ownership of Crosstex Energy Holdings Inc., please see "Security Ownership of Certain Beneficial Owners and Management."

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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 for Crosstex Energy, L.P. and our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated and summary pro forma financial and operating data for us as of and for the year ended December 31, 2002 and the six months ended June 30, 2003. The summary historical financial data for the four months ended April 30, 2000, the eight months ended December 31, 2000, and the years ended December 31, 2001 and 2002, are derived from the audited financial statements of Crosstex Energy, L.P. and its predecessor. The summary historical financial data for the six months ended June 30, 2002 and 2003 are derived from our unaudited financial statements 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 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 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 reflect our consolidated historical operating results as adjusted for the DEFS acquisition, the senior secured note offerings, this offering and, in the case of the pro forma statement of operations for the year ended December 31, 2002, our initial public offering. The summary pro forma financial data is derived from the unaudited pro forma financial statements. The pro forma balance sheet assumes that the issuance of $10.0 million of senior secured notes and this offering occurred on June 30, 2003. The pro forma statements of operations assume that the DEFS acquisition, the senior secured note offerings, this offering and our initial public offering occurred on January 1, 2002. 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. 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 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)

Crosstex Energy, L.P. is the successor to Crosstex Energy Services, Ltd. 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 subsequent to May 2000 due to the new basis of accounting.

(2)

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

(3)

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

(4)

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

(5)

We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental financial measure by management and by external users of our financial

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statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (a) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (b) our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing and capital structure; and (c) the viability of projects and the overall rates of return on alternative investment opportunities. EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles. EBITDA is not intended to represent cash flow. Because EBITDA excludes some, but not all, items that affect net income and these measures may vary among other companies, the EBITDA data presented may not be comparable to similarly titled measures of other companies.

The

following table reconciles EBITDA to net income (loss):

Our

predecessors were partnerships and had no income tax expense. EBITDA for the years ended December 31, 2001 and 2002 and the six months ended June 30, 2002 has been reduced by non-cash impairment charges of $2.9 million, $4.2 million and $3.2 million, respectively, and the six months ended June 30, 2003 has been reduced by non-cash stock-based compensation charges of $3.1 million.

(6)

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.

(7)

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

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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. Crosstex Energy GP, LLC has a conflicts committee, consisting of three independent members of its board of directors, that is available to review matters involving conflicts of interest. C. Roland Haden, Stephen A. Wells and Robert F. Murchison, all of whom are directors of Crosstex Energy GP, LLC, are members of the conflicts committee. Please read "Management—Directors and Executive Officers of Crosstex Energy GP, LLC" for a discussion of the directors of Crosstex Energy GP, LLC.

        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 have entered into an agreement with Crosstex Energy Holdings Inc. whereby it has agreed not to engage in the business of gathering, transmitting, treating, processing and marketing of natural gas. In addition, our general partner does not receive any management fee or other compensation for its management of us, but our general partner and its affiliates are reimbursed for general and administrative expenses incurred on our behalf. For the twelve month period ending in December 2003, 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, which we believe include the risks material to our business, 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;

•

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



•

the level of our processing and treating operations;



•

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



•

the price of natural gas;



•

the relationship between natural gas and NGL prices; and



•

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:

•

the level of capital expenditures we make;



•

the cost of acquisitions, if any;



•

our debt service requirements;



•

fluctuations in our working capital needs;



•

restrictions on distributions contained in our bank credit facility;



•

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



•

prevailing economic conditions; and



•

the amount of cash reserves established by our general partner in its sole 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 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.

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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.

        Competition is intense in many of our markets. The principal areas of competition include obtaining gas supplies and the marketing and transportation of natural gas and NGLs. Our competitors include major integrated oil companies, interstate and intrastate pipelines and natural gas gatherers and processors. Our competitors in the Texas Gulf Coast area include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services. Our competitors in Mississippi include Southern Natural Gas and Gulf South Pipeline Company. Some of our competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do.

        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. We may not 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 or in the level of drilling activity in our principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a 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 is 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, is 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 three components of our business: (1) the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; (2) certain processing contracts for our Gregory system whereby we are exposed to natural gas and NGL commodity price risks; and (3) part of our fee from the Seminole gas plant is based on a portion of the NGLs produced, and, therefore, is subject to 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 year ended December 31, 2002 and the six

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months ended June 30, 2003, we purchased approximately 6.2% and 8.8%, respectively, 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 $0.01 per gallon in the price of NGLs and an increase of $0.10 per MMBtu in the average price of natural gas for the six months ended June 30, 2003 would have resulted in a decrease in processing margins of approximately $109,051. For the six months ended June 30, 2003, we purchased approximately 22% 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. For example, in 2001, the NYMEX settlement price for natural gas for the prompt month contract ranged from a high of $9.98 per MMBtu to a low of $1.83 per MMBtu. In 2002, the same index ranged from $3.47 per MMBtu to $2.01 per MMBtu. For the six months ended June 30, 2003, the same index ranged from $8.79 per MMBtu to $4.76 per MMBtu. A composite of the OPIS Mt. Belvieu monthly average liquids price based upon our average liquids composition in 2001 ranged from a high of approximately $0.71 per gallon to a low of approximately $0.27 per gallon. In 2002, the same composite ranged from approximately $0.48 per gallon to approximately $0.27 per gallon. For the six months ended June 30, 2003, the same composite ranged from approximately $0.65 per gallon to approximately $0.46 per gallon.

        We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver contracted 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;



•

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.

If we are unable to integrate our recent acquisitions, or if we do not continue to make acquisitions on economically acceptable terms, our future financial performance may be limited.

        We recently completed the DEFS acquisition, which geographically expanded our operations into Alabama and Mississippi. For the year ended December 31, 2002, the DEFS assets would have constituted 33.3% of our pro forma gross margin and 15.8% of our pro forma EBITDA. We cannot assure you that we will successfully integrate this or any other acquisition into our operations, or that we will achieve the desired profitability from such acquisitions. Failure to successfully integrate these

18

substantial acquisitions could adversely affect our operations and cash flows available for distribution to our unitholders.

        Our future financial performance will depend, in part, on our ability to make acquisitions of assets and businesses at attractive prices. From time to time, we will evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. Any acquisition involves potential risks, including:

•

the inability to integrate the operations of recently acquired businesses or assets;



•

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



•

the loss of customers or key employees from the acquired businesses;



•

a significant increase in our indebtedness; and



•

potential environmental liabilities and title problems.

Management's assessment of these risks is necessarily inexact and may not reveal or resolve all existing or potential problems with an acquisition.

        If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of gas processing and transportation assets by large industry participants. A material decrease in such divestitures will limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

We have limited control over the development of certain assets because we are not the operator.

        As the owner of a non-operating interest in the Seminole gas processing plant, we do not have the right to direct or control the operation of the plant. As a result, the success of the activities conducted at the plant, which is operated by a third party, may be affected by factors outside of our control. The failure of the third-party operator to make decisions, perform its services, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations affecting the plant, including environmental laws and regulations, in a proper manner could result in material adverse consequences to our interest and adversely affect our results of operations.

We expect to encounter significant competition in any new geographic areas into which we seek to expand and our ability to enter such markets may be limited.

        With our acquisition of assets from DEFS, we have expanded our operations into new geographic areas. As we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas supplies and markets. Competitors in these new markets include companies larger than us, which have both lower capital costs and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, we may not be able to successfully develop acquired assets and markets located in new geographic areas and our results of operations could be adversely affected.

We are exposed to the credit risk of our customers and counterparties, 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 participants in the energy industry 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

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nonpayment or nonperformance by our 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 six months ended June 30, 2003, approximately 56% of our sales of gas which were 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. To the extent that Kinder Morgan Inc. 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 Inc. accounted for 22.4% of our revenues during the first six months of 2003, 27.5% of our revenues during 2002 and 23.9% of our revenues during 2001. Our agreements with our key customers provide for minimum volumes of natural gas that each customer must purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Our customers may default on their obligations to purchase the minimum volumes required under the applicable agreements. Our primary contract with Kinder Morgan Inc. expires in March 2006.

We have a limited combined operating history.

        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 gathering, processing and treating facilities. We are nearing completion of construction activities to expand our Gregory processing plant at an estimated cost of $8.0 million. The construction of gathering, processing and treating facilities requires the

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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 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 fully 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. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline systems which would cover damage to the pipelines. We are not insured against all environmental accidents which might occur, other than those considered to be sudden and accidental. Our business interruption insurance covers only our Gregory processing plant. 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 and our ability to raise capital.

        On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope. These attacks caused instability in the global financial markets and other industries, including the energy industry. 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. Instability in the financial markets as a result of terrorism, the war in Iraq or future developments could also affect our ability to raise capital.

        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.

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

        Upon completion of this offering, we expect our total outstanding long-term indebtedness to be approximately $46.6 million, including $40.0 million of senior secured notes, $5.9 million under the bank credit facility and approximately $0.7 million of other indebtedness. Payments of principal and interest on the indebtedness will reduce the cash available for distribution on the units. The bank credit facility and senior secured notes contain various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates, make distributions to our unitholders and capitalize on acquisition or other business opportunities. The bank credit facility and our senior secured notes also contain covenants requiring us to maintain certain financial ratios, such as debt to EBITDA, EBITDA to interest, current assets to current liabilities and minimum tangible net worth. We are prohibited from making any distribution to unitholders if such distribution would cause a default or an event of default under the bank credit facility or the senior secured notes. Each of the bank credit facility and the senior secured notes limits the use of borrowings under the bank credit facility to pay distributions to unitholders to $5.0 million over the term of the bank credit facility. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Indebtedness" for a discussion of the bank credit facility and senior secured notes.

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

        While the Federal Energy Regulatory Commission, or FERC, generally 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. 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 statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting 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

22

that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The "rural gathering exemption," however, may be restricted in the future, and it does not apply to our natural gas transmission pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements. See "Business—Regulation."

        Compliance with pipeline integrity regulations issued by the TRRC, or those soon to be issued by the United States Department of Transportation, or DOT, could result in substantial expenditures for testing, repairs and replacement. TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. In addition, the DOT is expected to issue regulations for interstate pipeline testing in late 2003. We expect our costs relating to compliance with the required testing under the TRRC regulations to be approximately $1.0 million in 2003 and between $1.0 million and $2.0 million in each of 2004 and 2005. If our pipelines fail to meet the safety standards mandated by the TRRC regulations, then we may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

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 may incur material environmental costs and liabilities. Furthermore, our insurance may not 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. See "Business—Environmental Matters."

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 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 currently have hedges in place on 130,000 MMBtu of gas per month at prices ranging from $3.45 per MMBtu to $5.56 per MMBtu for the period from July 1, 2003 to September 30, 2003,

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100,000 MMBtu of gas per month at prices ranging from $4.51 per MMBtu to $6.13 per MMBtu for the period from October 1, 2003 to December 31, 2003, 90,000 MMBtu of gas per month at prices ranging from $4.51 per MMBtu to $5.59 per MMBtu for the period from January 1, 2004 to March 31, 2004, 70,000 MMBtu of gas per month at prices ranging from $4.67 per MMBtu to $5.09 per MMBtu for the period from April 1, 2004 to June 30, 2004, and 30,000 MMBtu of gas per month at a price of $4.85 per MMBtu for the period from July 1, 2004 to December 31, 2004. We estimate that these quantities represent approximately 100%, 80%, 75%, 60% and 28% of the margin on natural gas that we will buy at a percentage of index and upon which we will be exposed to the risk of fluctuations in natural gas prices. We could 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."

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, and as a result our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. 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

Crosstex Energy Holdings Inc. controls our general partner and will own a 56% limited partner interest in us upon completion of this offering. 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 56% in us. In addition, Crosstex Energy Holdings Inc. owns and controls our general partner. Due to its control of our general partner and the size of its limited partner interest in us, Crosstex Energy Holdings Inc. effectively controls all limited partnership decisions, including any decisions related to the removal of 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

24

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



•

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 partner 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, except for certain limitations on general and administrative expenses which expire in December 2003.

Please read "Conflicts of Interest and Fiduciary Responsibilities" and "Certain Relationships and Related Transactions—Omnibus Agreement."

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

        Unlike the holders of common stock in a corporation, unitholders 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 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 affiliates of the general partner will control approximately 56.8% of all the units upon

25

completion of this offering, 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, 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 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 provide us with services for which we are charged reasonable fees as determined by our general partner in its sole discretion. In December 2003, the $6.0 million limit on such reimbursements will expire and expenses will most likely be higher and reduce the amount of cash available for distribution on the units. 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.

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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.

        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."

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 1,316,000 additional common units. 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

27

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. 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.

        You could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business, to the extent that a person who has transacted business with the partnership reasonably believes, based on your conduct, that you are a general partner. 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 a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the 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.

Equity securities in Crosstex Energy Holdings Inc. eligible for future sale may have adverse effects on the price of our common units.

        As of August 14, 2003, Crosstex Energy Holdings Inc. held 333,000 common units and 4,667,000 subordinated units, representing a 56% limited partnership interest in us after giving effect to this offering. Crosstex Energy Holdings' partnership interest in us represents substantially all of its assets. Crosstex Energy Holdings Inc. may, from time to time, issue equity securities or the present equity owners of Crosstex Energy Holdings Inc. may sell all or a portion of their equity securities in Crosstex Energy Holdings Inc. Sales of substantial amounts of equity securities in Crosstex Energy Holdings Inc., or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

Our common units have a limited trading history and a limited trading volume compared to other units representing limited partner interests.

        Our common units are traded publicly on the Nasdaq National Market under the symbol "XTEX." However, our common units have a limited trading history and daily trading volumes for our common units are, and may continue to be, relatively small compared to many other units representing limited partner interests quoted on the Nasdaq National Market. Although we have several market makers in our common units, this alone does not assure significant trading volume or liquidity. We cannot assure

28

you that this offering will increase the trading volume for our common units, and the price of our common units may, therefore, be volatile.

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 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

29

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.

Recent changes in federal income tax law could affect the value of our common units.

        On May 28, 2003, the Jobs and Growth Tax Relief Reconciliation Act of 2003 was signed into law, which generally reduces the maximum tax rate applicable to corporate dividends to 15%. This reduction could materially affect the value of our common units in relation to alternative investments in corporate stock, as investments in corporate stock may be more attractive to individual investors thereby exerting downward pressure on the market price of our common units.

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 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 are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

        We are registered with the IRS as a "tax shelter." Our tax shelter registration number is 02337000008. 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

30

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 own property or conduct business in Texas, Oklahoma, Louisiana, New Mexico, Arkansas, Mississippi and Alabama. Oklahoma, Louisiana, New Mexico, Arkansas, Mississippi and Alabama 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. Texas does not impose a franchise tax on partnerships at this time. 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 $50.9 million from the sale of the 1,500,000 common units offered by this prospectus, together with a capital contribution from our general partner of approximately $1.1 million to maintain its 2% general partner interest in our partnership, assuming an offering price of $36.55 per unit and after deducting underwriting discounts and estimated offering expenses. We intend to use all of the net proceeds of this offering to repay a portion of the borrowings under the bank credit facility incurred in connection with recent acquisitions and capital projects, including the DEFS acquisition (for which we incurred borrowings of $67.3 million). Please read "Prospectus Summary—Recent Developments—Recent Acquisitions—Duke Energy Field Services." We will use any net proceeds from the exercise of the over-allotment option to further repay borrowings under the bank credit facility.

        As of June 30, 2003, total borrowings under the bank credit facility were approximately $68.0 million, and it had a weighted-average interest rate of 4.49%. The bank credit facility was amended in June 2003, and has a maturity date of June 1, 2006. A portion of the proceeds from the funds borrowed under the bank credit facility between December 2002 and June 2003 was used for acquisitions, including the DEFS, Vanderbilt system and Will-O-Mills acquisitions. The remainder of such proceeds was used for capital projects, including the expansion of the Gregory processing plant, improvements to the Vanderbilt system and related facilities, the purchase, refurbishment and installation of treating plants, construction of a new gathering system and enhancements to, and maintenance of, existing assets.

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CAPITALIZATION

        The following table sets forth our capitalization as of June 30, 2003 on:

•

a historical basis;



•

a pro forma basis to give effect to the issuance of $10.0 million senior secured notes in July 2003 pursuant to the master shelf agreement; and



•

a pro forma as adjusted basis to give effect to the common units offered by this prospectus, our general partner's proportionate capital contribution and the application of the net proceeds from this offering as described in "Use of Proceeds."

        You should read our financial statements and notes that are included elsewhere in this prospectus for additional information about our capital structure.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

        Our common units are listed and traded on the Nasdaq National Market under the symbol "XTEX." Our common units began trading on December 12, 2002 at an initial public offering price of $20.00 per common unit. The following table shows the low and high closing sale prices per common unit, as reported by the Nasdaq National Market, for the periods indicated.

(a)

Through August 14, 2003.

(b)

For the quarter ended September 30, 2003, the board of directors of our general partner has authorized a distribution of $0.70 per unit, representing $0.20 in excess of the minimum quarterly distribution on all of our outstanding units.

(c)

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

        The last reported sale price of our common units on the Nasdaq National Market on August 14, 2003 was $36.55. As of July 3, 2003, there were approximately 2,600 holders of record of our common units.

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

        General.    Within approximately 45 days after the end of each quarter, we will distribute all of our available cash to unitholders of record on the applicable record date.