SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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)

     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 þ          No o

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

      As of April 1, 2005, the Registrant had 8,722,081 common units and 9,334,000 subordinated units outstanding.

TABLE OF CONTENTS

CROSSTEX ENERGY, L.P.

Condensed Consolidated Balance Sheets

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Operations

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners’ Equity

Three Months Ended March 31, 2005

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Comprehensive Income

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Cash Flows

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements

March 31, 2005

(Unaudited)

      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 consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2004.

      The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Partnership to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

      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 $276,000 and $209,000 was recognized during the three months ended March 31, 2005 and 2004, respectively.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      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):

      No Partnership or Crosstex Energy, Inc. (CEI) options were granted to officers or employees in 2005. 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.

      In 2004, 85,000 restricted shares in CEI were issued to members of management under its long-term incentive plan with an intrinsic value of $2,579,000. 80,000 of the CEI restricted shares vest over a five-year period and 5,000 of the restricted shares vest over a three-year period. The intrinsic value of the restricted shares is amortized into stock-based compensation expense over the vesting periods.

      In May 2005, the Partnership’s managing general partner amended its long-term incentive plan to increase the aggregate common unit options and restricted units under the plan from 1.4 million to 1.8 million.

      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, 2005 and 2004. The computation of diluted earnings per unit further assumes the dilutive effect of unit options and restricted units.

      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.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      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, 2005 and 2004 (in thousands):

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

      Net income is allocated to the general partner in an amount equal to its incentive distributions as described in Note (4). The remaining net income is allocated pro rata between the 2% general partner interest, the subordinated units, and the common units. The net income allocated to the general partner for incentive distributions was $1,998,000 and $953,000 for the three months ended March 31, 2005 and 2004, respectively.

      In December 2004, the FASB issued SFAS No. 123 (Revised 2004), Share-Based Payment (SFAS No. 123R), which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees and will be effective beginning January 1, 2006. We have previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R may have a significant impact on our financial statements. Although we have not determined the impact of SFAS No. 123R, the pro forma effect of recording compensation for all stock awards at fair value utilizing the Black-Scholes method for the three months ended March 31, 2005 and 2004 resulted in a decrease in our net income of $68,000 and $53,000, respectively.

      In April 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 American Electric Power (AEP) in a negotiated transaction for $73.7 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 in April through borrowings under its amended bank credit facility.

      Until December 31, 2004, the Partnership owned a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Partners, L.P. (CPP) and a 20.31% interest as a limited partner in CPP. The Partnership accounted for its investment in CPP under the equity method for the years ended December 31, 2002, 2003 and 2004 because it exercised significant influence in operating decisions as a general partner in CPP.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of the CPP Partnership for $5.1 million. This acquisition made the Partnership the sole limited partner and general partner of CPP, so the Partnership began consolidating its investment in CPP effective December 31, 2004.

      Operating results for the LIG assets have been included in the Statements of Operations since April 1, 2004, and operating results for the CPP assets have been included in the Statements of Operations since January 1, 2005. The following unaudited pro forma results of operations assume that the LIG acquisition occurred on January 1, 2004 (in thousands, except per unit amounts):

      As of March 31, 2005 and December 31, 2004, long-term debt consisted of the following (in thousands):

      On March 31, 2005, the Partnership amended the bank credit facility, increasing availability under the facility to $250 million, eliminating the distinction between an acquisition and working capital facility and extending the maturity date from June 2006 to March 2010. Additionally, an accordion feature built into the credit facility allows the Partnership to increase the availability to $350 million.

      In April 2005, the Partnership amended the shelf agreement governing the senior secured notes to increase its availability from $125 million to $200 million.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      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 $1,998,000 were earned by our general partner for the three months ended March 31, 2005. 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 $0.45 per unit was paid on February 16, 2005. The Partnership declared a first quarter 2005 distribution of $0.46 per unit to be paid on May 20, 2005.

      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 Partnership commonly enters into various derivative financial transactions which it does not designate as hedges. These include transactions called “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, and “storage swaps”. Swing swaps are generally short-time in nature (one month), and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Third party on-system financial swaps are hedges that the Partnership enters into on behalf of its customers who are connected to its systems, wherein the Partnership fixes a supply or market price for a period of time for its customer, and simultaneously enters into the derivative transaction. Marketing financial swaps are similar to on-system financial swaps, but are entered into for customers not connected to the Partnership’s systems. Storage swap transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements.

      The fair value of derivative assets and liabilities are as follows (in thousands):

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2005 (all gas quantities are expressed in British Thermal Units unless otherwise indicated). The remaining term of the contracts extend no later than December 2007, with no single contract longer than 6 months. The Partnership’s counterparties to hedging contracts include BP Corporation, UBS Energy and Total Gas & Power. Changes in the fair value of the Partnership’s derivatives related to third-party producers and customers gas marketing activities are recorded in earnings in the period the transaction is entered into. The effective portion of changes in 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 and the ineffective portion is recorded in earnings.

      In the first quarter of 2005, the Partnership recognized gains due to the ineffectiveness of certain cash flow hedges of $204,000 which is included in profit on energy trading activities. The Partnership also recognized a loss of $589,000 on the mark-to-market of its derivatives not designated as hedges in the first quarter of 2005.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      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.

      Assets and liabilities related to third party derivative contracts, swing swaps and storage swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as profit (loss) on energy trading activities along with the net operating results from Commercial Services 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):

      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, 2005 and 2004, the Partnership purchased natural gas from Camden in the amount

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

of approximately $9.1 million and $8.2 million, respectively, and received approximately $837,000 and $639,000, respectively, in treating fees from Camden.

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

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

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

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

      Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of the CPP Partnership for $5.1 million. This acquisition makes the Partnership the sole limited partner and general partner of CPP and the Partnership began consolidating its investment in CPP effective December 31, 2004.

      Each member of executive 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.

      The Partnership acquired assets from Duke Energy Field Services (“DEFS”) in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, 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. Under the purchase agreement, DEFS has retained liability for cleanup of the Conroe site. Moreover, a third-party company had assumed the remediation costs associated with the Conroe site. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe site.

      The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from historical operations has been identified at a number of sites within the acquired properties. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third-party company that specializes in remediation work. The Partnership does not expect to incur any material liability with these sites. The Partnership has disclosed these deficiencies to Louisiana Department of Environmental Quality and is working with the department to correct permit conditions and address modifications to facilities to bring them into compliance. The Partnership does not expect to incur any material environmental liability associated with these issues.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

      During the three months ended March 31, 2005, the Partnership charged $1.1 million to cost of sales for natural gas that was vented to the atmosphere as a result of a leak in one of its pipelines. Approximately $800,000 of additional costs will be recorded in April 2005 related to additional gas losses and the repair of the pipeline.

      On March 31, 2005, the Partnership received a $1.8 million deposit pursuant to a contract to sell certain idle equipment for $9 million. The sale is expected to close no later than September 2005. The deposit is recorded as a liability in the accompanying consolidated financial statements.

      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.

      In May 2003, four landowner groups filed suit against us in the 267th Judicial District Court in Victoria County, Texas seeking damages related to the expiration of an easement for a segment of one of our pipelines located in Victoria County, Texas. In 1963, the original owners of the land granted an easement for a term of 35 years, and the prior owner of the pipeline failed to renew the easement. The Partnership filed a condemnation counterclaim in the district court suit and it filed, in a separate action in the county court, a condemnation suit seeking to condemn a 1.38-mile long easement across the land. Pursuant to condemnation procedures under the Texas Property Code, three special commissioners were appointed to hold a hearing to determine the amount of the landowner’s damages. In August 2004, a hearing was held and the special commissioners awarded damages to the current landowners in the amount of $877,500. The Partnership has timely objected to the award of the special commissioners and the condemnation case will not be tried in the county court. The damages award by the special commissioners will have no effect and cannot be introduced as evidence in the trial. The county court will determine the amount that the Partnership will pay the current landowners for an easement across their land and will determine whether or not and to what extent the current landowners are entitled to recover any damages for the time period that there was not an easement for the pipeline on their land. Under the Texas Property Code, in order to maintain possession of and continued use of the pipeline until the matter has been resolved in the county court, the Partnership was required to post bonds and cash, each totaling the amount of $877,500, which is the amount of the special commissioners award. The Partnership is not able to predict the ultimate outcome of this matter.

      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, the LIG pipelines and processing plants located in Louisiana, and various other small systems. Also included in the Midstream division are the Partnership’s Commercial 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

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

to the segments on a pro rata basis based on the number of employees within the segments. Interest expense is allocated on a pro rata basis based on segment assets. Inter-segment sales are at cost.

      Summarized financial information concerning the Partnership’s reportable segments is shown in the following table.

      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. (“CEI”) 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 Gulf Coast of the United States. 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, 2005, 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 purchase and resell gas for a margin, or to gather, process, transport, market or treat gas for a fee. 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 March 31, 2005, we have invested over $320 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:

      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 41 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:

      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.

      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 purchase since January 2004 was the acquisition of LIG Pipeline Company.

      In April 2004 we acquired LIG Pipeline Company and its subsidiaries, which we collectively refer to as LIG, from a subsidiary of American Electric Power for $73.7 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 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 560,000 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.

      In December 2004 we acquired all of the outside limited and general partner interests of Crosstex Pipeline Partners, L.P., or CPP, for $5.1 million. This acquisition made us the sole limited partner and general partner of CPP, so we began consolidating our investment in CPP effective December 31, 2004.

      On January 2, 2005 we acquired all of the assets of Graco Operations for $9.25 million. Graco’s assets consisted of 26 treating plants and associated inventory.

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.

      Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $23.1 million for the three months ended March 31, 2005 compared to $15.3 million for the three months ended March 31, 2004, an increase of $7.8 million, or 51%. The LIG acquisition, effective April 1, 2004, and the CPP acquisition, effective December 31, 2004, accounted for $9.8 million and $0.5 million, respectively, of gross margin growth. These improvements were offset by a $1.1 million increase in cost of gas due to a physical gas leak and an additional $1.6 million increase in cost of gas related to the variance in system balance recognition between comparative quarters.

      During the first quarter and into part of April we experienced a line leak in a six inch lateral to one of our transmission pipelines in a remote and uninhabited area. As a result of the leak a total of 275,000 MMbtu was vented to the atmosphere. The total financial impact of the commodity loss is estimated at $1.9 million, of which $1.1 million was recognized in the first quarter. We are in the process of expanding our automated monitoring system on all of our pipelines that are not currently equipped with these devices. We believe that this type of monitoring system would have detected the leak much sooner and mitigated the amount of gas vented to the atmosphere. The line has been repaired and is back in service.

      Treating gross margin was $8.4 million for the three months ended March 31, 2005 compared to $5.8 million in the same period in 2004, an increase of $2.6 million, or 46%. The increase in treating plants from 56 plants in March 2004 to 87 plants in March 2005 contributed approximately $2.3 million in gross margin. Also contributing to the increase was a $0.3 million gross margin improvement for the Seminole plant due to an increase in volumes, fees, and higher liquid prices.

      Profit on energy trading activity decreased from a profit of $0.4 million for the three months ended March 31, 2004 to $45,000 for the three months ended March 31, 2005. Energy trading activity included approximately $0.4 million of net profit related to our Commercial Services activities during the first quarter of 2004 and 2005. The net profit from Commercial Services during the first quarter of 2005 was offset by a $0.6 million loss associated with derivatives for third-party on-system financial transactions and storage financial transactions that are considered energy trading activities. The Partnership recognized gains due to the

ineffectiveness of certain cash flow hedges of $0.2 million which is also included in profit on energy trading activities in 2005.

      Operating Expenses. Operating expenses were $11.5 million for the three months ended March 31, 2005, compared to $6.2 million for the three months ended March 31, 2004, an increase of $5.3 million, or 85%. The LIG acquisition accounted for $3.6 million of the additional operating expenses, while the net treating plant additions increased expenses by $1.0 million and non-routine or planned pump and equipment repairs on several plants increased expenses by $0.3 million. An expense of $0.5 million was recognized in the first quarter of 2005 to accrue up to the amount of our insurance deductible associated with damages claimed when natural gas liquids that were being removed from one of our lines pursuant to normal operating procedures inadvertently diverted into customers facilities.

      General and Administrative Expenses. General and administrative expenses were $6.2 million for the three months ended March 31, 2005 compared to $3.6 million for the three months ended March 31, 2004, an increase of $2.6 million, or 72%. The increase was primarily due to increases in staffing ($2.2 million) and infrastructure ($0.2 million) associated with the requirements of the LIG acquisition and growth in our treating business and its other assets as discussed above. We also expensed approximately $0.3 million during the first quarter of 2005 associated with the attempted acquisition of south Texas pipeline assets from Transco.

      (Gain)/ Loss on Sale of Property. In March 2005 we recognized a $44,000 gain on the sale of certain treating equipment for $193,000. 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 $6.9 million for the three months ended March 31, 2005 compared to $4.4 million for the three months ended March 31, 2004, an increase of $2.5 million, or 57%. The increase related to the LIG assets purchased in April 2004 was $1.1 million. New treating plants placed in service resulted in an increase of $0.7 million. The remaining $0.7 million increase in depreciation and amortization is a result of expansion projects and other new assets, including major office expansion and computer purchases during the last half of 2004.

      Interest Expense. Interest expense was $3.4 million for the three months ended March 31, 2005 compared to $1.2 million for the three months ended March 31, 2004, an increase of $2.2 million, or 183%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between three-month periods (weighted average rate of 6.44% in 2005 compared to 5.9% in 2004).

      Net Income. Net income for the three months ended March 31, 2005 was $3.2 million compared to $5.7 million for the three months ended March 31, 2004, a decrease of $2.5 million. This was generally the result of the increase in gross margin of $10.1 million, including profit (loss) from energy trading activities, between comparative quarters from 2004 to 2005, offset by increases in ongoing cash costs totaling $10.1 million for operating expenses, general and administrative expenses, and interest expense as discussed above. Depreciation and amortization expense also increased $2.5 million.

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, 2004.

Liquidity and Capital Resources

      Cash Flows. Net cash used in operating activities was $5.0 million for the three months ended March 31, 2005 compared to cash provided by operations of $6.6 million for the three months ended March 31, 2004. Income before non-cash income and expenses was $10.4 million in 2005 and $10.6 million in 2004. Changes in working capital used $15.4 million in cash flows from operating activities in 2005 and used $4.0 million in cash flows from operating activities in 2004. Changes in working capital used $15.4 million in cash flows in 2005 primarily due to payments on various accrued obligations during the first quarter of 2005.

      Net cash used in investing activities was $21.1 million and $8.1 million for the three months ended March 31, 2005 and 2004, respectively. Net cash used in investing activities during 2005 related to the $9.3 million Graco acquisition, buying, refurbishing and installing treating plants, connecting new wells to various systems, pipeline integrity, pipeline relocation and various other internal growth projects. During 2004, 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 $22.6 million for the three months ended March 31, 2005 compared to $2.3 million used in financing activities for the three months ended March 31, 2004. Net bank borrowings of $47.0 million were used to fund the internal growth projects, the $9.3 million Graco acquisition, and to fund working capital needs discussed above. Distributions to partners totaled $10.2 million in the first quarter of 2005 compared to $7.5 million in the first quarter of 2004. Drafts payable decreased by $14.2 million for the three months ended March 31, 2005 as compared to an increase in drafts payable of $7.5 million providing cash for financing activities for the three months ended March 31, 2004. 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 and 2005.

Indebtedness

      As of March 31, 2005 and December 31, 2004, long-term debt consisted of the following (dollars in thousands):

      On March 31, 2005, we amended the bank credit facility, increasing availability under the facility to $250 million, eliminating the distinction between an acquisition and working capital facility and extending the maturity date from June 2006 to March 2010. Additionally, an accordion feature built into the credit facility allows us to increase the availability to $350 million. Under the amended credit agreement, borrowings bear interest at our option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. We will incur quarterly commitment fees based on the unused amount of the credit facilities. The amendment to the credit facility also adjusted financial covenants requiring us to maintain:

      The Partnership was in compliance with all debt covenants at March 31, 2005 and expects to be in compliance for the next twelve months.

      In April, 2005, we amended our shelf agreement governing our senior secured notes to increase its availability from $125 million to $200 million.

      Our contracted cash obligations as of March 31, 2005 with respect to long term debt is as follows:

      There were no material changes to operating leases or other contractual cash obligations during the first quarter of 2005.

Recent Accounting Pronouncements

      In December 2004, the FASB issued SFAS No. 123 (Revised 2004), Share-Based Payment (SFAS No. 123R), which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees and will be effective beginning July 1, 2005. We have previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R may have a significant impact on our financial statements. Although we have not determined the impact of SFAS No. 123R, the pro forma effect of recording compensation for all stock awards at fair value utilizing the Black-Scholes method for the three months ended March 31, 2005 and 2004, resulted in a decrease in our net income of $68,000 and $53,000, respectively.

Disclosure Regarding Forward-Looking Statements

      This Quarterly 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:

      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.

      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 7% 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 resale margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. We have hedged approximately 78% of our exposure to gas price fluctuations through June 2006 and approximately 80% of our exposure to liquid price fluctuations through the end of 2005.

      Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

      We have commodity price risk associated with our processed volumes of natural gas. We currently process gas under four main types of contractual arrangements:

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

      The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. 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.

      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, 2005, we had $80 million of indebtedness outstanding under floating rate debt. The impact of a 1% 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 $800,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at March 31, 2005.

      Operational Risk. As with all mid-stream energy companies and other industrials, we have operational risk associated with operating our plant and pipeline assets that can have a financial impact, either favorable or unfavorable, and as such risk must be effectively managed. We view our operational risk in the following categories.

      General Mechanical Risk — both our plants and pipelines expose us to the possibilities of a mechanical failure or process upset that can result in loss of revenues and replacement cost of either volume losses or damaged equipment. These mechanical failures manifest themselves in the form of equipment failure/ malfunction as well as operator error. We are proactive in managing this risk on two fronts. First we effectively hire and train our operational staff to operate the equipment in a safe manner, consistent with defined process and procedures and second we perform preventative and routine maintenance on all of our mechanical assets.

      Measurement Risk — In complex midstream systems such as ours, it is normal for there to be differences between gas measured into our systems and those measured out of the system which is referred to as system balance. These system balances are normally due to changes in line pack, gas vented for routine operational and non-routine reasons, as well as due to the inherent inaccuracies in the physical measurement of gas. We employ the latest gas measurement technology when appropriate, in the form of EFM (Electronic Flow Measurement) computers. Nearly all of our new supply and market connections are equipped with EFM. Retro-fitting older measurement technology is done on a case-by-case basis. Electronic digital data from these devices can be transmitted to a central control room via radio, telephone, cell phone, satellite or other means. With EFM computers, such a communication system is capable of monitoring gas flows and pressures in real-time and is commonly referred to as SCADA (Supervisory Control And Data Acquisition). We expect to continue to increase our reliance on electronic flow measurement and SCADA, which will further increase our awareness of measurement discrepancies as well as reduce our response time should a pipeline failure occur.

      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, 2005 in alerting them in a timely manner to material

information required to be disclosed in our periodic reports filed with the Securities and Exchange Commission.

      There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2005 that has materially affected, or is reasonable likely to materially affect, our internal controls over financial reporting. We implemented an enterprise-wide accounting system on January 1, 2005. We expect this new system to improve our control environment as its full capabilities are deployed throughout our operations during 2005.

PART II — OTHER INFORMATION

      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):

* Filed herewith.

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 13th day of May, 2005.