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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K/A
Amendment No. 1

Commission file number: 000-50067

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

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

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

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

        Indicate by check mark whether registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE: None.

CROSSTEX ENERGY, L.P.
FORM 10-K/A
INTRODUCTORY NOTE

        This Amendment No. 1 to annual report on Form 10-K/A ("Form 10-K/A") is being filed to amend our annual report on Form 10-K for the year ended December 31, 2003, which was originally filed on March 10, 2004 ("Original Form 10-K"). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of items 6, 7, 8 and 9A of Part II and item 15 of Part IV, as amended, as well as certain currently dated certifications. Unaffected items have not been repeated in this Amendment No. 1.

        In July 2004, we determined that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. As a result of correcting these errors, we have restated our consolidated balance sheets as of December 31, 2002 and 2003, our consolidated statement of operations for the year ended December 31, 2002, our consolidated statements of changes in partners' equity for the years ended December 31, 2002 and 2003, our consolidated statement of comprehensive income for the year ended December 31, 2002 and our consolidated statement of cash flows for the year ended December 31, 2002. We have also restated our notes to consolidated financial statements as necessary to reflect the adjustments. The net effect of the adjustments resulted in a reduction in net income and comprehensive income for the year ended December 31, 2002 by $1.7 million and a reduction in partners' equity and working capital as of December 31, 2002 and 2003. Please read note 2 to the accompanying consolidated financial statements for a discussion of the adjustments.

        This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the adjustments described above. Such events include, among others, the events described in our quarterly report on Form 10-Q for the quarter ended March 31, 2004 and the events described in our current reports on Form 8-K filed after the filing of the Original Form 10-K. We will file with the Securities and Exchange Commission an amendment to our quarterly report on Form 10-Q for the quarter ended March 31, 2004 to reflect changes therein required as a consequence of the adjustments described above.

TABLE OF CONTENTS

DESCRIPTION

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GLOSSARY OF TERMS

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

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

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CROSSTEX ENERGY, L.P.

PART II

Item 6. Selected Financial Data

        The following table sets forth selected historical financial and operating data of Crosstex Energy, L.P. and our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, L.P. or our predecessor, Crosstex Energy Services, Ltd. The investment in our predecessor by Yorktown Energy Partners IV, L.P. in May 2000 resulted in the dissolution of the predecessor partnership and the creation of a new partnership with the same organization, purpose, assets, and liabilities. Accordingly, the financial statements of our predecessor for 2000 are divided into the four months ended April 30, 2000 and the eight months ended December 31, 2000 because a new basis of accounting was established effective May 1, 2000 to give effect to the Yorktown transaction. In addition, the summary historical financial and operating data of Crosstex Energy Services, Ltd. include the results of operations of the Arkoma system beginning in September 2000, the Gulf Coast system beginning in September 2000, the CCNG system, which includes the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, beginning in May 2001, the Vanderbilt system beginning in December 2002 and the DEFS assets beginning in June 2003.

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

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(1)

Restated to reflect the correction of clerical errors that resulted in certain reconciling items relating to 2002 not being properly cleared. See Note 2 to the consolidated financial statements. The adjustments resulted in a reduction in net income for the year ended December 31, 2002 by $1.7 million and a reduction in partners' equity and working capital as of December 31, 2002 and 2003 by $1.7 million.

(2)

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

(3)

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

(4)

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.

(5)

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

(6)

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

(7)

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

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

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

Restatement

        In July 2004, we determined that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. As a result of these errors and as more fully discussed in the Introductory Note to this Amendment No. 1, certain financial and other information contained herein has been restated to reflect adjustments described in Note 2 to the accompanying consolidated financial statements. Please read Note 2 for a discussion of the adjustments.

Overview

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

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

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

•

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



•

processing natural gas at our processing plants;

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•

treating natural gas at our treating plants;



•

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



•

providing producer services.

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

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

        We generate treating revenues under three arrangements:

•

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



•

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



•

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

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

        Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore, do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.

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

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

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

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

•

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



•

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



•

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



•

The Rosita treating plant was treating approximately 25,000 MMBtu of gas per day at the time of its acquisition. The Rosita treating plant is operated in the Partnership's Treating

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

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

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

Commodity Price Risk

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

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

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

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

6

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

(1)

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

(2)

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

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

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

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

•

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

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negatively affected in periods where the value of natural gas is high relative to the value of NGLs.

•

For the year ended December 31, 2003, we purchased approximately 84% of the natural gas volumes on our Gregory system at a spot or market price less a discount that includes a fixed margin for gathering, processing and marketing the natural gas and NGLs at our Gregory processing plant with no risk of loss or gain in processing the natural gas. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas. We anticipate purchasing increasing percentages of gas under fixed fee arrangements as opposed to contracts under which the processing economics are for our account.

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

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

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

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Results of Operations

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

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

        Gross Margin.    Midstream gross margin was $46.7 million for the year ended December 31, 2003 compared to $23.2 million (restated) for the year ended December 31, 2002, an increase of $23.5 million, or 101%. The largest increase in gross margin was due to the acquisition of assets from Duke Energy Field Services on June 30, 2003. These assets added gross margin of $9.4 million. The CCNG system had significant growth due to an increase in on-system volume and the addition of the Hallmark lateral, resulting in an increase in margin of $4.7 million. We acquired the Vanderbilt Gathering system on December 31, 2002; this system added gross margin of $4.4 million. Gregory gathering system and Gregory processing plant had increased margin of $2.6 million. These systems had significant growth in volume due to producer drilling activity in the area, to which we responded with the Gregory plant expansion during 2003. The Gulf Coast system had increased margin of $1.2 million despite the fact that volumes declined. The reason for the decline in volumes was because we sourced two markets from Vanderbilt the last half of 2003 that were previously sourced from the Gulf Coast system. We had an increase in volume and increase in margin due to a large customer taking gas from our system for 12 months in 2003 and only 6 months in 2002, and we had increased margin due to renegotiation of producer contracts. The Arkoma system also had increased volume, creating an increase in margin of $0.8 million.

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

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

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

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

        (Profit) Loss on Energy Trading Activities.    The profit on energy trading activities was $1.9 million for the year ended December 31, 2003 compared to $1.7 million (restated) for the year ended December 31, 2002, an increase of $0.2 million, or 12%. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $2.2 million in 2003 and $1.8 million in 2002, an increase of $0.4 million, or 22%. This increase is primarily due to an increase in our producer services volumes. In addition, losses of $0.3 million and $0.1 million (restated) relating primarily to options bought and/or sold in the management of the company's Enron position were booked in 2003 and 2002, respectively.

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

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

        Net Income (Loss).    Net income for the year ended December 31, 2003 was $15.2 million compared to $0.3 million (restated) for the year ended December 31, 2002, an increase of $14.9 million. This was generally the result of the increase in gross margin of $27.5 million from

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2002 to 2003, offset by increases in ongoing cash costs for operating expenses and interest expense as discussed above. Non-cash charges for depreciation and amortization expenses and stock based compensation also increased.

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

        Gross Margin.    Midstream gross margin was $23.2 million (restated) for the year ended December 31, 2002 compared to $17.9 million for the year ended December 31, 2001, an increase of $5.3 million, or 30%. The Corpus Christi system, the Gregory gathering system and the Gregory processing plant were acquired in May 2001. The gross margin from these assets for the 12-month period of 2002 exceeded that of the 8-month period in 2001 by $6.9 million. This was offset by lower margin of $0.8 million at the Arkoma system and $0.4 million at the Gulf Coast system due to lower prices in 2002.

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

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

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

        Impairments.    Impairment expense was $4.2 million in 2002 compared to $2.9 million in 2001. Intangible assets were booked associated with the contract values of certain treating plants and other assets in conjunction with the Yorktown investment in May 2000. Impairment charges in 2002 and 2001 are associated with writing off certain of these intangible contract values. The charges in 2001 relate to intangible contract values associated with the Jonesville processing plant, which was transferred out of the partnership in conjunction with the initial public offering. Impairment charges in 2002 are primarily associated with intangible contract values at 4 specific treating plants. Two of the plants are still working at the location where they were sited at the time of the Yorktown investment, but had experienced recent declines in cash flows. As the operator of the wells behind these plants had recently told the company that it was canceling its drilling plans in the area, the declines are expected to continue until the plants are relocated. The other two treating plants were removed from service during 2002 at the locations where they were sited at the time of the Yorktown investment, and therefore the intangible contract values associated with that particular location were deemed impaired. (One of the plants was immediately contracted at another location at a higher rental rate than previously in effect. The other plant is currently in inventory.)

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        (Profit) Loss on Energy Trading Activities.    The profit on energy trading activities was $1.7 million (restated) for the year ended December 31, 2002 compared to a loss of $3.7 million for the year ended December 31, 2001, an increase of $5.4 million. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $1.8 million in 2002 and $1.9 million in 2001. This variance is primarily due to the $5.7 million reserve booked in 2001 against the company's Enron receivable due to Enron Corporation's December 2001 bankruptcy.

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

        Interest Expense.    Interest expense was $2.7 million for the year ended December 31, 2002 compared to $2.3 million for the year ended December 31, 2001, an increase of $0.4 million, or 21%. The increase relates primarily to bank debt incurred in the acquisitions of the CCNG assets in May 2001, offset by lower interest rates.

        Net Income (Loss).    Net income (loss) for the year ended December 31, 2002 was $0.3 million (restated) compared to ($3.9) million for the year ended December 31, 2001, an increase of $4.2 million. Gross margin increased by $8.0 million from 2001 to 2002, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, and interest expense as discussed above. Non-cash charges for depreciation and amortization expenses and for impairment expense also increased, offset by the gain on energy trading activities.

Critical Accounting Policies

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

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

        We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and natural gas liquids. We also manage our price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices.

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

        Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. In accordance with SFAS No. 133, all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

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

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

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

        Impairment of Long-Lived Assets.    In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

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

•

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



•

the availability and prices of natural gas supply;



•

our ability to negotiate favorable sales agreements;



•

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



•

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



•

competition from other midstream companies, including major energy producers.

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

Liquidity and Capital Resources

        Cash Flows.    Net cash provided by operating activities was $46.5 million for the year ended December 31, 2003 compared to cash used by operations of $5.7 million for the year ended December 31, 2002. Income before non-cash income and expenses was $33.6 million in 2003 and $12.3 million (restated) in 2002. Changes in working capital provided $12.8 million in cash flows from operating activities in 2003 and used $18.0 million (restated) in cash flows from operating activities in 2002. Income before non-cash income and expenses increased between years primarily due to asset acquisitions as discussed in "Results of Operations—Year Ended December 31, 2003 compared to year ended December 31, 2002." Changes in working capital provided $12.8 million in cash flows in 2003 primarily due to $3.5 million in prepayments by certain customers in December 2003 combined with $3.8 million due to delays in collecting from a few large customers in December 2002 until January 2003. In addition, property cost accruals increased by approximately $1.5 million due to an increase in capital projects late in 2003 as compared to 2002. The remaining changes in working capital were due to timing of receipts and disbursements in the ordinary course of business.

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

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        Net cash provided by (used in) financing activities was $62.7 million and $39.9 million for the years ended December 31, 2003 and 2002, respectively. Financing activities in 2003 relate principally to the funding of the Duke assets acquisition and internal growth projects discussed above from bank borrowings and proceeds from the sale of common units discussed below. Financing activities during 2002 primarily represented funding or refunding of the partnership's debt and working capital needs through bank borrowings and net proceeds from our initial public offering in December 2002 and partner contributions. Financing activities also included a decrease in drafts payable of $17.1 million for the year ended December 31, 2003 and an increase in drafts payable of $25.6 million for the year ended December 31, 2002. In order to reduce our interest costs, we borrow money to fund outstanding checks as they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility.

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

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

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

•

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



•

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

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

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

        Subsequent Event.    We entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power

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for $76.2 million. The acquisition will increase our pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. We will finance the acquisition through borrowings under our existing bank credit facility, issuance of additional senior notes or other financing alternatives.

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

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

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

Description of Indebtedness

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

•

a $70.0 million senior secured revolving acquisition facility; and



•

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

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

        The working capital and letter of credit facility will be used for ongoing working capital needs, letters of credit, distributions to partners and general partnership purposes, including future acquisitions and expansions. At December 31, 2003 we had $30.3 million of letters of credit issued under the $50 million working capital and letter of credit facility, leaving approximately $19.7 million available for future issuances of letters of credit and/or cash borrowings. The aggregate amount of borrowings under the working capital and letter of credit facility is subject to a borrowing base requirement relating to the amount of our cash and eligible receivables (as defined in the credit agreement), and there is a $25.0 million sublimit for cash borrowings. This facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital and letter of credit facility may be re-borrowed. We are required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.

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

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

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

•

incur indebtedness;



•

grant or assume liens;



•

make certain investments;



•

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



•

make distributions;



•

change the nature of its business;



•

enter into certain commodity contracts;

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•

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



•

engage in transactions with affiliates.

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

•

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



•

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



•

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



•

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

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

•

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



•

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



•

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



•

certain ERISA events involving us or our subsidiaries;



•

cross defaults to certain material indebtedness;



•

certain bankruptcy or insolvency events involving us or our subsidiaries;



•

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



•

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

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

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

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

        The senior secured notes are redeemable, at our operating partnership's option and subject to certain notice requirements, at a purchase price equal to 100% of the principal amount together

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with accrued interest, plus a make-whole amount determined in accordance with the master shelf agreement.

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

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

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

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

Credit Risk and Significant Customers

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

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

Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2001, 2002, or 2003. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

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Environmental

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

Recent Accounting Pronouncements

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

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

        In January 2003, the FASB issued Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ended after December 15, 2002. The adoption of this statement had no impact on our results of operations or financial condition.

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

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that one of our joint venture interests, as described in Note 4 to the financial statements, will be consolidated in our financial statements when FIN No. 46R is adopted in March 2004.

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

Disclosure Regarding Forward-Looking Statements

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

•

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



•

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



•

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



•

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



•

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



•

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



•

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



•

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



•

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



•

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

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•

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



•

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

        Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

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

Item 8. Financial Statements and Supplementary Data

        The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-42 and S-1 of this Report and are incorporated herein by reference.

Item 9A. Controls And Procedures

        We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, to the extent and in the case described in the following paragraph, our disclosure controls and procedures were not effective as of December 31, 2003 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

        In July 2004, we determined during the course of internal reviews that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. We identified these errors and promptly brought them to the attention of our audit committee and auditors. As a result of correcting these errors, in this annual report on Form 10-K/A, we have restated our consolidated balance sheets as of December 31, 2002 and 2003, our consolidated statement of operations for the year ended December 31, 2002, our consolidated statements of changes in partners' equity for the years ended December 31, 2002 and 2003, our consolidated statement of comprehensive income for the year ended December 31, 2002 and our consolidated statement of cash flows for the year ended December 31, 2002. We have also restated our notes to consolidated financial statements as necessary to reflect the adjustments. These errors resulted from a deficiency in the procedures to reconcile the detail accounts receivable and accounts payable subledgers to the general ledger. Our independent auditors, KPMG LLP, have reviewed these matters and advised our Audit Committee that the deficiency constituted a material weakness as defined in Statements of Auditing Standards No. 60. In light of the discovery of these errors, we have implemented new procedures for reconciling subledgers to the general ledger and disposition and resolution of reconciling items on a timely basis. Management believes that controls are now in place to ensure that similar errors do not occur again.

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

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PART IV

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

(a)

Financial Statements and Schedules



(1)

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



(2)

See Schedule II—Valuation and Qualifying Accounts on Page S-1.



(3)

Exhibits

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

23

24

*

Previously filed.

**

Filed herewith.

+

Compensatory benefit plan or arrangement in which directors and executive officers are eligible to participate.

(b)

Reports on Form 8-K.

        On November 12, 2003, Crosstex Energy, L.P. filed or furnished a Current Report on Form 8-K (dated as of November 13, 2003) which included its press release as Exhibit 99.1 announcing its financial results for the quarter ended September 30, 2003.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 9th day of August 2004.

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INDEX TO FINANCIAL STATEMENTS

F-1

Report of Independent Registered Public Accounting Firm

The Partners
Crosstex Energy, L.P.:

        We have audited the accompanying consolidated balance sheets of Crosstex Energy, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of operations, changes in partners' equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2003. In connection with the audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

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

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Crosstex Energy, L.P. and subsidiaries as of December 31, 2003 and 2002, and the consolidated results of their operations, comprehensive income, and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects the information set forth therein.

        As explained in note 3 to the consolidated financial statements, effective January 1, 2001, the Partnership changed its method of accounting for derivatives. Also, as explained in note 3 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of amortizing goodwill.

        As discussed in note 2 to the accompanying consolidated financial statements, the accompanying balance sheets as of December 31, 2003 and 2002, the consolidated statements of changes in partners' equity for the years ended December 31, 2003 and 2002 and the consolidated statements of operations, cash flows and comprehensive income for the year ended December 31, 2002 have been restated.

F-2

CROSSTEX ENERGY, L.P.

Consolidated Balance Sheets

December 31, 2003 and 2002

(In thousands)

See accompanying notes to consolidated financial statements.

F-3

CROSSTEX ENERGY, L.P.

Consolidated Statements of Operations

(In thousands, except per unit amounts)

See accompanying notes to consolidated financial statements.

F-4

CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners' Equity

Years ended December 31, 2003 (Restated), 2002 (Restated) and 2001

(In thousands)