SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-Q

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

2501 CEDAR SPRINGS, SUITE 600
DALLAS, TEXAS 75201
(Address of principal executive offices)
(Zip Code)

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

        Indicate by check mark whether registrant (1) 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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý        No o

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

        As of April 28, 2004, the Registrant had 8,747,326 common units and 9,334,000 subordinated units outstanding.

TABLE OF CONTENTS

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CROSSTEX ENERGY, L.P.

Consolidated Balance Sheets
(In thousands)

See accompanying notes to consolidated financial statements.

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CROSSTEX ENERGY, L.P.

Consolidated Statements of Operations
(In thousands, except per unit amounts)

(Unaudited)

See accompanying notes to consolidated financial statements.

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CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners' Equity
Three Months ended March 31, 2004
(In thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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CROSSTEX ENERGY, L.P.

Consolidated Statements of Comprehensive Income
(In thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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CROSSTEX ENERGY, L.P.

Consolidated Statements of Cash Flows
(In thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements
March 31, 2004
(Unaudited)

(1) General

Unless the context requires otherwise, references to "we","us","our" or the "Partnership" mean Crosstex Energy, L.P. and its consolidated subsidiaries.

        Crosstex Energy, L.P. (the Partnership), a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, treating, processing and marketing of natural gas. The Partnership connects the wells of natural gas producers to its gathering systems in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas to a variety of markets. In addition, the Partnership purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.

        The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. These consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2003.

        (a) Long-Term Incentive Plans

        The Partnership applies the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), and the related interpretations in accounting for the long-term incentive plans. In accordance with APB No. 25 for fixed stock and unit options, compensation is recorded to the extent the fair value of the stock or unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. In addition, compensation expense is recorded for variable options based on the difference between fair value of the stock or unit and exercise price of the options at period end. Compensation expense of $209,000 and $2,504,000 was recognized during the three months ended March 31, 2004 and 2003, respectively.

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        Had compensation cost for the Partnership been determined based on the fair value at the grant date for awards in accordance with SFAS No. 123, Accounting for Stock Based Compensation, the Partnership's net income would have been as follows (in thousands, except per unit amounts):

        The fair value of each option is estimated on the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions used for Partnership unit grants in 2004:

        No Crosstex Energy, Inc. (CEI) options were granted to officers or employees in 2004. Stock based compensation associated with the CEI option plan with respect to officers and employees is recorded by the Partnership since CEI has no operating activities, other than its interest in the Partnership.

        CEI modified certain outstanding options attributable to its shares of common stock 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. The total number of CEI options which were modified was approximately 364,000. These modified options have been accounted for using variable accounting as of the option modification date. The Partnership accounted for the modified options as variable options until the holders elect to cash out the options or the election to cash out the options lapsed. CEI is

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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 are accounted for as fixed options. Beginning in the first quarter of 2003, the Partnership recognized stock compensation expense based on the estimated fair value at period end of the options modified. The Partnership recognized stock-based compensation expense of approximately $2.5 million related to the variable options for the quarter ended March 31, 2003.

        In February 2004, 75,000 restricted shares in CEI were issued to senior management under its long-term incentive plan with an intrinsic value of $2,183,000. In February 2004, 1,406 restricted units with an intrinsic value of $29,000 were issued to a director, at his election, for his 2004 annual director fee. These restricted units vest over a five-year period and the intrinsic value of the units is amortized into stock based compensation expense over the vesting period.

        (b) Earnings per Unit and Anti-Dilutive Computations

        Basic earnings per unit was computed by dividing net income by the weighted average number of limited partner units outstanding for the three months ended March 31, 2004 and 2003. The computation of diluted earnings per unit further assumes the dilutive effect of unit options.

        Effective March 29, 2004, the Partnership completed a two-for-one split on its outstanding limited partnership units. All unit amounts for prior periods presented herein have been restated to reflect this unit split.

        The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three months ended March 31, 2004 and 2003 (in thousands):

        All outstanding units were included in the computation of diluted earnings per unit.

        (c) New Accounting Pronouncement

        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

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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 ending after March 15, 2004. In January 2004, the Partnership adopted FIN No. 46R and began consolidating its joint venture interest in the Crosstex DC Gathering, J.V. (CDC), previously accounted for using the equity method of accounting. The consolidated carrying amount for the joint venture is based on the historical costs of the assets, liabilities and non-controlling interests of the joint venture since its formation in January 2003 which approximates the carrying amount of the assets, liabilities and non-controlling interests in the consolidated financial statements as if FIN No. 46R had been effective upon inception of the joint venture.

(2) Significant Asset Purchases and Acquisitions

        On June 30, 2003, the Partnership completed the acquisition of certain assets from Duke Energy Field Services, L.P. (DEFS) for $68.1 million, including the effect of certain purchase price adjustments. The assets acquired included: the Mississippi pipeline system, a 12.4% interest in the Seminole gas processing plant, the Conroe gas plant and gathering system and the Alabama pipeline system. The Partnership has accounted for this acquisition as a business combination in accordance with SFAS No. 141, Business Combinations. We have utilized the purchase method of accounting for this acquisition with an acquisition date of June 30, 2003.

        Operating results for the DEFS assets are included in the Statements of Operations since June 30, 2003. Unaudited pro forma results of operations as if the acquisition from DEFS had been acquired on January 1, 2003 are as follows (in thousands, except per unit amounts):

(3) Investment in Limited Partnerships and Note Receivable

        The Partnership owns a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Partners, L.P. (CPP), a 20.31% interest as a limited partner in CPP, 50% interest in the J.O.B. J.V. and a 50% interest in CDC. In January 2004, the Partnership began consolidating its investment in CDC. The Partnership accounts for its investments in J.O.B. J.V. and CPP under the equity method, as it exercises significant influence in operating decisions as a general partner in CPP and as a 50% owner in the joint venture. Under this method, the Partnership carries its investments at cost and records its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them are recorded as a reduction in the Partnership's investment in the affiliated partnership.

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        In connection with the formation of CDC, the Partnership agreed to loan the CDC Partner up to $1.5 million for their initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC Partner's 50% share of distributable cash flow to repay the loan. Any balance remaining on the note is due in August 2007. The current portion of loan receivable of $747,000 from the CDC Partner is included in current notes receivable as of March 31, 2004. The remaining balance of $838,000 is included in other non-current assets as of March 31, 2004.

(4) Long-Term Debt

        As of March 31, 2004 and December 31, 2003, long-term debt consisted of the following (in thousands):

        In conjunction with the April 2004 acquisition of the LIG Pipeline Company and its subsidiaries discussed in Note (9), the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70 million to $100 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50 million to $100 million.

        In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement which expires on November 1, 2004. The Partnership has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged. The fair value of the interest rate swap at March 31, 2004 was a $181,000 liability and is included in fair value of derivative liabilities.

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(5) Partners' Capital

Cash Distributions

        In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48% of amounts we distribute in excess of $0.375 per unit. Incentive distributions totaling $953,000 were earned by our general partner for the three months ended March 31, 2004. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.

        The Partnership's fourth quarter distribution on its common and subordinated units of $0.375 per unit was paid on February 13, 2004. The Partnership declared a first quarter 2004 distribution of $0.40 per unit to be paid on May 14, 2004.

(6) Derivatives

        The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge prices and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.

        The fair value of derivative assets and liabilities, excluding the interest rate swap, are as follows (in thousands):

        Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than March 2005, with no single contract longer than 6 months. The Partnership's counterparties to hedging contracts include Williams Energy Services Company, Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, and Duke Energy Trading and Marketing. Changes in the fair value of the Partnership's derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes in

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

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

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        Assets and liabilities related to Producer Services that are accounted for as derivative contracts held for trading purposes are included in the fair value of derivative assets and liabilities. Producer Services operating and results are recorded net as profit (loss) on energy trading activities in the consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

(7) Transactions with Related Parties

General and Administrative Expense Cap

        The Partnership had a $6.0 million annual ($1.5 million quarterly) general and administrative cap for the twelve-month period ended in December 2003, per its partnership agreement. CEI bore the cost of any excess general and administrative expenses. During the three months ended March 31, 2003, the Partnership had excess expenses of approximately $0.5 million. The general partner is also reimbursed for direct charges it incurs on behalf of partnership business development activities. There were no direct charges for the three months ended March 31, 2003.

Camden Resources, Inc.

        The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. (Camden). Camden is an affiliate of the Partnership by way of equity investments made by Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P., collectively the major shareholder in CEI, in Camden. During the three months ended March 31, 2004 and 2003, the Partnership purchased natural gas from Camden in the amount of approximately $8.2 million and $2.7 million, respectively, and received approximately $18,000 and $61,000 in treating fees from Camden.

Crosstex Pipeline Partners, L.P.

        The Partnership had related-party transactions with Crosstex Pipeline Partners, L.P. (CPP), as summarized below:

•

During the three months ended March 31, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $2.25 million and $1.2 million and paid for transportation of approximately, $11,622 and $13,800, respectively, to CPP.



•

During the three months ended March 31, 2004 and 2003, the Partnership received a management fee from CPP in the amount of approximately $31,000 and $31,000, respectively.



•

During the three months ended March 31, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $20,000 and $52,000, respectively.

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(8) Commitments and Contingencies

        (a) Employment Agreements

        Each member of senior management of the Partnership is a party to an employment contract with the general partner. The employment agreements provide each member of senior management with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person's employment.

        (b) Environmental Issues

        The Partnership acquired two assets from DEFS in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, DEFS has entered into an agreement with a third-party Company pursuant to which the remediation costs associated with the Conroe site have been assumed by this third-party Company that specializes in remediation work. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.

        (c) Other

        The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

        The Partnership receives notices from pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. These allocation corrections normally have little impact on the Partnership's gross margin because the Partnership balances its purchases and sales in the pipelines and both the purchase and sale on the pipeline system require corrections. As of March 31, 2004 and December 31, 2003, a subsidiary of the Partnership was involved in 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 billed the Partnership's subsidiary for approximately $1.2 million of gas deliveries that occurred in the period from December, 2000 through February, 2001. The Partnership's subsidiary, in turn, billed its customer who was overpaid due to the allocation error. The customer is disputing its liability for such amount, asserting that the corrected billing was untimely. The allocation error occurred prior to the Partnership's acquisition of the subsidiary involved in the dispute. The Partnership has an indemnity from the seller of the subsidiary for liabilities arising prior to the acquisition date. As of March 31, 2004 and December 31, 2003, the Partnership has 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.

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The Partnership believes the customer's dispute of the receivable is without merit, and further believes that it is protected against loss by its right to indemnification.

(9) Segment Information

        Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Partnership's reportable segments consist of Midstream and Treating. The Midstream division consists of the Partnership's natural gas gathering and transmission operations and includes the Mississippi System, the Conroe System, the Gulf Coast System, the Corpus Christi System, the Gregory Gathering System located around the Corpus Christi area, the Arkoma system in Oklahoma, the Vanderbilt System located in south Texas, and various other small systems. Also included in the Midstream division are the Partnership's Producer Services operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. Included in the Treating division are four gathering systems that are connected to the treating plants and the Seminole plant located in Gaines County, Texas.

        The Partnership evaluates the performance of its operating segments based on earnings before income taxes and accounting changes, and after an allocation of corporate expenses. Corporate expenses are allocated to the segments on a pro rata basis based on assets. Inter-segment sales are at cost.

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        Summarized financial information concerning the Partnership's reportable segments is shown in the following table. There are no other significant non-cash items.

(10) Subsequent Event (Unaudited)

        On April 1, 2004, the Partnership acquired, through its wholly-owned subsidiary Crosstex Louisiana Energy, L.P., the LIG Pipeline Company and its subsidiaries (LIG Inc., Louisiana Intrastate Gas Company, L.L.C., LIG Chemical Company, LIG Liquids Company, L.L.C. and Tuscaloosa Pipeline Company) (collectively, "LIG") from a subsidiary of American Electric Power in a negotiated transaction for $76.2 million. LIG consists of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to south and southeast Louisiana. The Partnership financed the acquisition through borrowings under its amended bank credit facility.

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Item 2. 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.

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 three months ended March 31, 2004, 73% of our gross margin was generated in the Midstream division, with the balance in the Treating division. 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.

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

•

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



•

processing natural gas at our processing plants;



•

treating natural gas at our treating plants;



•

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



•

providing producer services.

        The bulk of our operating profits are derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See "Item 3. Quantitative and Qualitative Disclosures about Market Risk—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 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 57% and 67% of the operating income in our Treating division for the three months ended March 31, 2004 and 2003, respectively;

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•

a fixed fee for operating the plant for a certain period, which accounted for approximately 38% and 26% of the operating income in our Treating division for the three months ended March 31, 2004 and 2003, respectively; or



•

a fee arrangement in which the producer operates the plant, which accounted for approximately 5% and 7% of the operating income in our Treating division for the three months ended March 31, 2004 and 2003, respectively.

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

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

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

        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. We acquired the assets from Duke Energy Field Services ("DEFS") 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 and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for major oil companies in west Texas.

        Our most recent asset purchase was completed in April 2004, when we acquired LIG and its subsidiaries from a subsidiary of American Electric Power ("AEP") for $76.2 million in cash. The principal assets acquired consist of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to the south and southeast Louisiana and five processing plants, three of which are currently idle, that straddle the pipeline in three locations and have a total processing capability of 663,000 MMbtu/d. The system has a throughput capacity of 900,000 MMbtu/d and average throughput at the time of our acquisition was approximately 580,000 MMbtu/d. Customers include power plants, municipal gas systems, and industrial markets located principally in the industrial corridor between New Orleans and Baton Rouge. The LIG system is connected to several interconnected pipelines and the Jefferson Island Storage facility providing access to additional system supply. We financed the LIG acquisition through borrowings under our bank credit facility. Since this acquisition closed on April 1, 2004, it is not reflected in the March 31, 2004 financial statements.

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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.

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003

        Gross Margin.    Midstream gross margin was $15.3 million for the three months ended March 31, 2004 compared to $7.9 million for the three months ended March 31, 2003, an increase of $7.4 million, or 94%. The CCNG, Vanderbilt, and Arkoma systems had growth in on-system transmission and gathering volumes of 35% and the Gregory plant had growth in processed volumes of 40% due to the plant expansion in 2003, resulting in an aggregate increase in gross margin of $3.5 million. Gross margin also increased by $3.4 million between comparative three-month periods due to the acquisition of assets from DEFS in June 2003.

        Treating gross margin was $5.8 million for the three months ended March 31, 2004 compared to $2.8 million in the same period in 2003, an increase of $2.9 million, or 103%. A significant portion of the increase was due to $1.9 million of gross margin contributed by the Seminole Plant, which was one of the assets acquired from DEFS in June 2003. In addition, 22 new plants were in service during the first quarter of 2004 as compared to the corresponding quarter in 2003 which generated an additional $1.2 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.1 million because five plants that were in service during the first quarter of 2003 were held in inventory during the first quarter of 2004.

        Operating Expenses.    Operating expenses were $6.2 million for the three months ended March 31, 2004, compared to $3.2 million for the three months ended March 31, 2003, an increase of $3.0 million, or 94%. An increase of $1.5 million was associated with the acquisition of assets from DEFS in June 2003. Costs for our technical services and general operations support increased by approximately $0.6 million due to staff additions to operate the assets acquired in June 2003 from DEFS and to manage other construction projects. The growth in treating plants in service increased operating expenses by $0.6 million.

        General and Administrative Expenses.    General and administrative expenses were $3.6 million for the three months ended March 31, 2004 compared to $1.5 million for the three months ended

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March 31, 2003, a increase of $2.1 million, or 139%. The increase was due in part 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 borne by the general partner. Had the cap not been in place, general and administrative expenses would have been $2.0 million, resulting in an actual increase from 2003 to 2004 of $1.6 million. The increase was primarily due to increases in staffing associated with the requirements of the DEFS acquisition and growth in the Partnership's treating business and its other assets as discussed above.

        Stock Based Compensation.    Stock based compensation expense decreased from $2.5 million in the first quarter of 2003 to $0.2 million in the first quarter of 2004. During 2003, certain outstanding CEI options were accounted for using variable accounting due to a "cash-out" modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The "cash-out" modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, the remaining CEI options are accounted for as fixed options. Stock based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.

        (Profit) Loss on Energy Trading Activities.    The profit on energy trading activities was $0.4 million for the three months ended March 31, 2004 compared to $0.1 million for the three months ended March 31, 2003, an increase of $0.3 million. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $0.5 million in the first quarter of 2004 and $0.3 million in the first quarter of 2003, an increase of $0.2 million.

        Loss on Sale of Property.    In March 2004, we sold one of our small gathering systems located in East Texas for $100,000 and recognized a loss on sale of $296,000.

        Depreciation and Amortization.    Depreciation and amortization expenses were $4.4 million for the three months ended March 31, 2004 compared to $2.4 million for the three months ended March 31, 2003, an increase of $2.0 million, or 81%. The increase related to the DEFS assets purchased in June 2003 was $1.2 million. New treating plants placed in service resulted in an increase of $0.2 million. The remaining $0.6 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant.

        Interest Expense.    Interest expense was $1.2 million for the three months ended March 31, 2004 compared to $0.4 million for the three months ended March 31, 2003, an increase of $0.8 million, or 182%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between three-month periods (weighted average rate of 5.9% in 2004 compared to 4.6% in 2003).

        Net Income.    Net income for the three months ended March 31, 2004 was $5.7 million compared to $0.8 million for the three months ended March 31, 2003, an increase of $4.9 million. This was generally the result of the increase in gross margin of $10.4 million between comparative quarters from 2003 to 2004, offset by increases in ongoing cash costs for operating expenses and interest expense as discussed above. Depreciation and amortization and stock based compensation expenses also increased.

Critical Accounting Policies

        Information regarding the Partnership's Critical Accounting Policies is included in Item 7 of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2003.

Liquidity and Capital Resources

        Cash Flows.    Net cash provided by operating activities was $6.6 million for the three months ended March 31, 2004 compared to cash provided by operations of $18.8 million for the three months

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ended March 31, 2003. Income before non-cash income and expenses was $10.6 million in 2004 and $5.8 million in 2003. Changes in working capital used $4.0 million in cash flows from operating activities in 2004 and provided $13.1 million in cash flows from operating activities in 2003. Income before non-cash income and expenses increased between periods primarily due to asset acquisitions as discussed in "Results of Operations—Three Months Ended March 31, 2004 Compared to Year Ended March 31, 2003." Changes in working capital used $4.0 million in cash flows in 2004 primarily due to payments on various accrued obligations during the first quarter of 2004.

        Net cash used in investing activities was $8.1 million and $4.7 million for the three months ended March 31, 2004 and 2003, respectively. Net cash used in investing activities during 2004 related to buying, refurbishing and installing treating plants, connecting new wells to various systems, pipeline integrity, pipeline relocation and various other internal growth projects. During 2003, net cash used in investing activities primarily related to internal growth projects including the Gregory plant expansion and buying, refurbishing and installing treating plants.

        Net cash provided by financing activities was $2.3 million for the three months ended March 31, 2004 compared to $15.3 million used in financing activities for the three months ended March 31, 2003. Net bank borrowings of $2.0 million were used to fund the internal growth projects discussed above. Distributions to partners totaled $7.5 million in the first quarter of 2004. There were no cash distributions in the first quarter of 2003 since the Partnership has only been public since December 2002. Drafts payable increased by $7.5 million providing cash for financing activities for the three months ended March 31, 2004 as compared a decrease in drafts payable of $13.1 million using cash from financing activities for the three months ended March 31, 2003. In order to reduce our interest costs, we do not borrow money to fund outstanding checks until 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 March 31, 2004.

Indebtedness

        As of March 31, 2004 and December 31, 2003, long-term debt consisted of the following (in thousands):

        In conjunction with the April 2004 LIG acquisition discussed above, the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70.0 million to $100.0 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50.0 million to $100.0 million.

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Disclosure Regarding Forward-Looking Statements

        This report on Form 10-Q 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-Q, 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;



•

our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Our operations are subject to 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 from 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

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environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition;

•

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; and



•

our common units may not have significant trading volume or liquidity, and the price of our common units may be volatile and may decline if interest rates increase.

        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 3. Quantitative and Qualitative Disclosures about Market Risk

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

        Commodity Price Risk.    Approximately 9.2% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 7.0% of the gas we purchased during the three months ended March 31, 2004. Our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the three months ended March 31, 2004, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have changed our processing margin by $24,000. Changes in natural gas prices indirectly may impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.

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

        The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market

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purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

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

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

        Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than March 2005, with no single contract longer than 6 months. Our counterparties to hedging contracts include Williams Energy Services Company, Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, and Duke Energy Trading and Marketing. Changes in the fair value of our derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes in the fair value of cash flow

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

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

        Interest Rate Risk.    We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. At March 31, 2004, we had $22.0 million of indebtedness outstanding under floating rate debt. We have interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein we have swapped floating rates for fixed rates of 2.29% and the applicable margin through November 1, 2004. The impact of a 100 basis point increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $103,000 per year. This amount has been determined by

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considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at March 31, 2004.

Item 4. 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 the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

        There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2004 that has materially affected, or is reasonable likely to materially affect, our internal controls over financial reporting.

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PART II—OTHER INFORMATION

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

        Effective March 29, 2004, Crosstex Energy, L.P. completed a two-for-one split on its outstanding limited partnership units.

Item 6. Exhibits and Reports on Form 8-K

(a)

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):

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*

Filed herewith.

(b)

Reports on Form 8-K

        On February 18, 2004, Crosstex Energy, L.P. filed a Current Report on Form 8-K, Items 5, 7 and 9, (dated as of February 17, 2004) announcing it's execution of a definitive agreement for the acquisition of the LIG Pipeline Company and its subsidiaries from American Electric Power for $76.2 million with an anticipated closing date within 90 days.

        On February 27, 2004, Crosstex Energy, L.P. filed a Current Report on Form 8-K, Items 7 and 12, which included its press release as Exhibit 99.1 announcing its financial results for the three and twelve months ended December 31, 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 7th day of May 2004.

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QuickLinks

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Item 4. Controls and Procedures

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Item 6. Exhibits and Reports on Form 8-K