UNITED STATES

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 Exchange Act).     Yes þ  No o

      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes o  No þ

      As of October 31, 2005, the Registrant had 8,834,312 common units, 9,334,000 subordinated units and 1,495,410 senior 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

Nine Months Ended September 30, 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

September 30, 2005

(Unaudited)

(1) General

      Crosstex Energy, L.P., 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 in the United States of America 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, 2004. Certain reclassifications have been made to the consolidated financial statements for the prior year periods to conform to the current presentation.

      The preparation of financial statements in accordance with generally accepted accounting principles 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 the exercise price of the options at period end for unexercised variable options. Certain fixed awards were modified during 2005 to accelerate vesting resulting in compensation expense of $0.5 million based on the difference between the fair value of the stock or units at the date of acceleration and the exercise price of the options.

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):

      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 the nine months ended September 30, 2005:

      The exercise price for 174,049 unit options granted in June 2005 was based on the market value of the units on January 1, 2005 which was less than the market value on the date of grant. The market value in excess of the exercise price totaling $0.8 million is amortized into stock-based compensation ratably over the three year vesting period.

      No Crosstex Energy, Inc. (CEI) options were granted to officers or employees of the Partnership in 2005. Stock-based compensation associated with the CEI long-term incentive 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 June 2005, the Partnership issued 111,552 restricted units to senior management and employees under its long-term incentive plan with an intrinsic value of $4.1 million. CEI issued 86,762 restricted common shares to senior management and employees of the Partnership with an intrinsic value of $3.9 million. These restricted units and CEI restricted common shares vest on January 1, 2008, and the intrinsic value of the restricted units and restricted common shares is amortized into stock-based compensation ratably over the vesting periods. Unit

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

distributions paid on the restricted units, which are phantom units, prior to vesting are considered cash compensation expense and are charged to general and administrative expense.

      Stock-based compensation expense totaled $1.1 million and $2.7 million for the three and nine months ended September 30, 2005, respectively. The amounts included in general and administrative expenses were $1.0 million and $2.4 million for the respective three- and nine-month periods and in operating expenses were $95,000 and $305,000 for the respective three- and nine-month periods. Stock-based compensation expense of $513,000 was recognized in the nine months ended September 30, 2005 related to the accelerated vesting of 7,060 unit options and 10,000 CEI common share options. Stock-based compensation expense of $1.0 million and $1.5 million was recognized during the three and nine months ended September 30, 2005, respectively, related to the amortization of restricted units and CEI restricted common shares. Stock-based compensation expense for the nine months ended September 30, 2005 also includes $.4 million of payroll taxes associated with CEI stock option exercises and CEI contributed capital for the same amount to reimburse the Partnership for these taxes.

      In May 2005, the Partnership’s general partner amended the Partnership’s 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 and nine months ended September 30, 2005 and 2004. The computation of diluted earnings per unit further assumes the dilutive effect of unit options, restricted units and senior subordinated 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.

      The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2005 and 2004 (in thousands):

      All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding for the period presented.

      Net income is allocated to the general partner in an amount equal to its incentive distributions as described in Note (4). In June 2005, the Partnership amended its partnership agreement to allocate the expenses attributable to CEI stock options and restricted stock all to the general partner to match the related general partner contribution

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for such items. Therefore, beginning in the second quarter of 2005, the general partner’s share of net income is reduced by stock-based compensation expense attributed to CEI stock options and restricted stock. The remaining net income after incentive distributions and CEI-related stock-based compensation is allocated pro rata between the 2% general partner interest, the subordinated units, and the common units. The following table reflects CEI’s general partner share of net income:

      For the three months ended September 30, 2005, the general partner was allocated $2.0 million of net income and total net income was $1.1 million, resulting in a net loss allocation to the limited partners of $0.9 million.

      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 will impact our financial statements. We reviewed the impact of SFAS No. 123R and we believe that the pro forma effect of recording compensation for all stock awards at fair value utilizing the Black-Scholes method for the three and nine months ended September 30, 2005 and 2004 presented in Note 1(b) above is not materially different.

      In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB Statement No. 143. FIN 47 is effective at December 31, 2005, and is not expected to affect the Partnership’s financial position or results of operations.

(2) Significant Acquisition

      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

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 2004 through borrowings under its amended bank credit facility.

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

(3) Long-Term Debt

      As of September 30, 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. The availability under the credit facility was increased to $750 million on November 1, 2005 for the acquisition of assets from El Paso Corporation discussed in Note (9).

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

(4) Partners’ Capital

      On June 24, 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including our general partners’ $1.1 million capital contribution. The senior subordinated units were issued at $33.44 per unit, which represents a discount of 13.7% to the market value of common units on such date, and will automatically convert to common units on a one-for-one basis on February 24, 2006. The senior subordinated units will receive no distributions until their conversion to common units.

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 (other than the senior subordinated unitholders) and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the 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 $2.5 million and $6.7 million were earned by our general partner for the three months and nine months ended September 30, 2005, respectively. 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 has declared a third quarter 2005 distribution of $0.49 per unit to be paid on November 15, 2005.

(5) Derivatives

      The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and to 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 transactions include “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, and “storage swaps”. Swing swaps are generally short-term 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 customers, 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 swaps transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements.

      In August 2005 the Partnership acquired puts, or rights to sell a portion of the liquids from the plants at a fixed price over a two-year period beginning January 1, 2006, as part of the overall risk management plan related to the acquisition of the El Paso assets as discussed in Note (9). Because the underlying volumes relate to assets which, at September 30, 2005, were not yet owned by the Partnership, the puts do not qualify for hedge accounting and are marked to market through the Partnership’s Consolidated Statement of Operations for the three and nine months ended September 30, 2005.

      The components of gain/loss on derivatives in the Consolidated Statements of Operations are (in thousands):

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      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 September 30, 2005 (all gas quantities are expressed in British Thermal Units and liquids are expressed in gallons). The remaining term of the contracts extend no later than October 2009, with no single contract longer than six months. The Partnership’s counterparties to derivative contracts include BP Corporation, Total Gas & Power and J. Aron & Co., a subsidiary of Goldman Sachs. 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.

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

      In the first nine months of 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $1.5 million. In the first nine months of 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.7 million. As of September 30, 2005, an unrealized pre-tax derivative fair value loss of $12.1 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). This entire fair value loss is expected to be reclassified into earnings through June 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

      The settlement of futures contracts and basis swap agreements related to October 2005 gas production reduced gas revenue by approximately $2.3 million.

      In the first nine months of 2005, net losses on liquids swap hedge contracts decreased liquids revenue by approximately $0.6 million. As of September 30, 2005, an unrealized pre-tax derivative fair value loss of $2.0 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). $1.8 million of the fair value loss is expected to be reclassified into earnings in 2005 and in 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

      Assets and liabilities related to third party derivative contracts, swing swaps, storage swaps and puts 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 on a net basis as gain (loss) on derivatives in the consolidated statement of

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

operations. The Partnership estimates the fair value of all of its energy trading contracts using actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

(6) Transactions with Related Parties

      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 in Camden by Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P., collectively the major shareholder in CEI. During the three months ended September 30, 2005 and 2004, the Partnership purchased natural gas from Camden in the amount of approximately $21.1 million and $10.3 million, respectively, and received approximately $0.7 million and $0.6 million in treating fees from Camden. The Partnership purchased natural gas from Camden in the amount of approximately $41.8 million and $28.5 million for the nine months ended September 30, 2005 and 2004, respectively, and received approximately $1.9 million and $1.8 million, respectively, in treating fees from Camden.

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

      Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of CPP 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.

(7) Commitments and Contingencies

      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.

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The Partnership acquired assets from Duke Energy Field Services, or 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 has 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 was identified during due diligence at a number of sites owned by the acquired companies. 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. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it discovered to the Louisiana Department of Environmental Quality and is working with the department to correct these deficiencies and to address modifications to facilities to bring them into compliance. The Partnership does not expect to incur any material environmental liability associated with these issues.

      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 now be tried in the county court. The damages awarded by the special commissioners will have no effect on 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 deposit of $877,500 is reflected in current assets as of September 30, 2005. The Partnership is not able to predict the ultimate outcome of this matter.

(8) 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, the LIG pipelines and processing plants located in Louisiana and various other

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 minority interest, and after an allocation of corporate expenses. Corporate expenses are allocated 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. The 2004 segment data information has been adjusted to conform to these allocation methods.

      Summarized financial information concerning the Partnership’s reportable segments is shown in the following table. The information includes all significant non-cash items.

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Subsequent Events

      On November 1, 2005 the Partnership acquired El Paso Corporation’s processing and liquids business in South Louisiana for $486 million. The assets acquired include 2.3 billion cubic feet per day of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines. The primary facilities and other assets the Partnership acquired consist of: (1) the Eunice processing plant and fractionation facility; (2) the Pelican processing plant; (3) the Sabine Pass processing plant; (4) a 23.85% interest in Blue Water gas processing plant; (5) the Riverside fractionator and loading facility; (6) the Cajun Sibon pipeline and (7) the Napoleonville natural gas liquid storage facility.

      The Partnership financed the acquisition with borrowings of approximately $380 million under its bank credit facility, net proceeds of approximately $105 million from the private placement of Senior Subordinated Series B Units discussed below, and approximately $2 million of equity contributions from Crosstex Energy GP, L.P., the general partner of the Partnership. In connection with the acquisition, the Partnership amended its bank credit facility to, among other things, increase the borrowing capacity to $750 million of revolving credit borrowings.

      On November 1, 2005, the Partnership sold 2,850,165 Senior Subordinated Series B Units in a private equity placement for net proceeds of approximately $107 million, including a $2 million capital contribution from the Partnership’s general partner and expenses associated with the sale. The Senior Subordinated Series B Units will not participate in the third quarter distribution, and will convert to common units on a one-for-one basis on November 14, 2005. The placement closed concurrently with the closing of the purchase transaction of the El Paso assets and the proceeds were used to fund a portion of the transaction as discussed above.

CROSSTEX ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. (CEI) on July 12, 2002 to indirectly acquire 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 and in Mississippi and Louisiana. 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 nine months ended September 30, 2005, 73% of our gross margin was generated in the Midstream division with the balance in the Treating division. We manage our business by focusing on gross margin 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 September 30, 2005, we have invested over $400 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 commercial 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 the south and southeast Louisiana and five processing plants, including three idle plants, 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 which provides 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. On May 1, 2005 we acquired all of the assets of Cardinal Gas Services for $6.7 million. Cardinal’s assets consisted of nine gas treating plants, 19 operating wellhead gas processing plants for dewpoint suppression, and equipment inventory.

      In March 2005 we entered into a contract to sell an idle processing plant, which was acquired in April 2004 as part of the LIG acquisition, for $9.0 million. We received deposits totaling $3.6 million in March and June 2005 pursuant to this contract. The sale closed in September 2005. The gain of $8 million on the sale of this plant was recognized in the third quarter of 2005.

      In September 2005 we began construction of the North Texas Pipeline project. This 122-mile pipeline project in the Barnett Shale formation is expected to be completed in the first quarter of 2006.

Subsequent Events

      On November 1, 2005 we acquired El Paso Corporation’s processing and liquids business in South Louisiana for $486 million. The assets acquired include 2.3 billion cubic feet per day of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines. The primary facilities and other assets we acquired consist of: (1) the Eunice processing plant and fractionation facility; (2) the Pelican processing plant; (3) the Sabine Pass processing plant; (4) a 23.85% interest in the Blue Water gas processing plant; (5) the Riverside fractionator and loading facility; (6) the Cajun Sibon pipeline and (7) the Napoleonville natural gas liquid storage facility.

      We financed the acquisition with borrowings of approximately $380 million under our bank credit facility, net proceeds of approximately $105 million from the private placement of Senior Subordinated Series B Units discussed below, and approximately $2 million of equity contributions from our general partner. On November 1, 2005 and in connection with the acquisition, we amended our bank credit facility to, among other things, increase the borrowing capacity to $750 million of revolving credit borrowings.

      On November 1, 2005, we sold 2,850,165 Senior Subordinated Series B Units in a private equity placement for net proceeds of approximately $107 million, including our general partner’s $2 million capital contribution and expenses associated with the sale . The Senior Subordinated Series B Units will not participate in the third quarter distribution, and will convert to common units on a one-for-one basis on November 14, 2005. The placement closed concurrently with the closing of the purchase transaction of the El Paso assets and the proceeds were used to fund a portion of the transaction as discussed above.

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 September 30, 2005 Compared to Three Months Ended September 30, 2004

      Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $28.8 million for the three months ended September 30, 2005 compared to $22.5 million for the three months ended September 30, 2004, an increase of $6.3 million, or 28%. Relatively high and volatile natural gas prices, and abnormal basis differentials during the third quarter of 2005, created favorable market opportunities on several systems. The impact of these high and volatile gas prices on midstream operations was a gross margin increase of $4.3 million. Operational improvements and volume increases on various systems contributed margin growth of $1.5 million. The acquisition of all outside interests in CPP as of January 1, 2005 accounted for $0.3 million of the increase in

gross margin. An expansion of the Arkoma system also accounted for a gross margin increase of $0.3 million during the quarter. Profit on energy trading activity decreased from a profit of $0.6 million for the three months ended September 30, 2004 to $0.3 million for the three months ended September 30, 2005. The decrease in profit on energy trading activities is primarily due to a volume decrease associated with contracts not renewed in 2005.

      Treating gross margin was $10.3 million for the three months ended September 30, 2005 compared to $6.6 million in the same period in 2004, an increase of $3.7 million, or 55%. The increase in treating plants in service from 67 plants at September 30, 2004 to 111 plants at September 30, 2005 contributed approximately $3.0 million to the increase in gross margin. Existing plant assets contributed $0.5 million in gross margin growth due primarily to plant expansion projects and increased volumes. The acquisition and installation of dew point control plants in 2005 contributed an additional $0.2 million to gross margin.

      Operating Expenses. Operating expenses were $13.9 million for the three months ended September 30, 2005 compared to $10.0 million for the three months ended September 30, 2004, an increase of $3.8 million, or 38%. Midstream operating expenses increased by $1.9 million compared to the same quarter 2004. A $.5 million increase was due to the acquisition of CPP and expansion at both Arkoma and CDC. The remaining $1.4 million was an increase in costs on various other systems. Treating operating expenses increased $1.8 million due to the growth in the treating business from 67 plants in 2004 to 111 at September 30, 2005..

      General and Administrative Expenses. General and administrative expenses were $8.1 million for the three months ended September 30, 2005 compared to $5.1 million for the three months ended September 30, 2004, an increase of $3.0 million, or 59%. The increase was partially due to a $1.2 million increase in the bonus accrual during the third quarter of 2005 over the comparative quarter in 2004 because we expect to meet the bonus performance measures at a higher level than was previously assumed. Other variances were $0.6 million in employee costs for labor and benefits associated with the increase in our employee base and $0.3 million training and travel related costs. General and administrative expenses included $1.0 million of stock-based compensation expense for the three months ended September 30, 2005 compared to $0.2 million of stock-based compensation expense for the three months ended September 30, 2004, accounting for a $0.8 million variance. The increase was due to granting of restricted units and restricted CEI shares in June 2005.

      Gain/ Loss on Derivatives. The third quarter of 2005 includes a $2.0 million loss associated with derivatives for third party on-system financial transactions and storage financial transactions primarily due to the increase in commodity prices during the third quarter of 2005. We also recognized income due to the ineffectiveness of certain cash flow hedges of $0.3 million and an $11.5 million loss on puts acquired in the third quarter of 2005 related to the acquisition of the El Paso assets. As part of the overall risk management plan related to the November 2005 acquisition of the El Paso assets, we acquired puts, or rights to sell a portion of the liquids from the plants at a fixed price over a two-year period beginning January 1, 2006 for a premium of $18.7 million. Because the underlying volumes relate to assets which were not yet owned by us when we acquired the puts in August, the puts do not qualify for hedge accounting in the third quarter and were marked to market through our consolidated statement of operations. The puts represent options, but not the obligation, to sell the related underlying liquids volumes at a fixed price. As the price of the underlying liquids increased significantly in the period, the value of the puts declined by $11.5 million, which writedown is reflected in gain/loss on derivatives.

      Gain/ Loss on Sale of Property. A gain of $8.0 million on the sale of an idle processing plant was recognized in the three month period ending September 30, 2005. The gain was partially offset by a $0.4 million net loss on other small assets sold. Assets sold during 2005 did not significantly contribute to operating cash flows.

      Depreciation and Amortization. Depreciation and amortization expenses were $7.8 million for the three months ended September 30, 2005 compared to $6.2 million for the three months ended September 30, 2004, an increase of $1.7 million, or 27%. New treating plants placed in service resulted in an increase of $0.9 million and expansion projects and other growth projects resulted in an increase of $0.8 million.

      Net Income. Net income for the three months ended September 30, 2005 was $1.1 million compared to $5.9 million for the three months ended September 30, 2004, a decrease of $4.9 million. The increase in gross margin of $10.0 million between comparative quarters from 2004 to 2005 was partially offset by increases

totaling $6.8 million in ongoing cash costs for operating expenses and general and administrative expenses as discussed above. The increase in gross margin was further offset by an increase in depreciation and amortization expense totaling $1.7 million. Income in the quarter ending September 30, 2005 included the $8.0 million gain on disposition of an idle processing plant which was offset by a $13.3 million loss on derivatives, including an $11.5 million loss on the puts associated with the El Paso acquisition.

     Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

      Gross Margin and Profit on Commercial Services Activities. Midstream gross margin was $76.9 million for the nine months ended September 30, 2005 compared to $60.6 million for the three months ended September 30, 2004, an increase of $16.3 million, or 27%. The largest portion of this increase was due to the acquisition of the LIG assets on April 1, 2004, which accounted for $8.5 million of the increase to midstream gross margin. Relatively high and volatile natural gas prices, and abnormal basis differentials during the quarter, created favorable market opportunities off several systems. The impact of these high and volatile gas prices on midstream operations was a gross margin increase of $4.3 million. Operational improvements and volume increases on the various systems contributed margin growth of $2.4 million. The acquisition of all outside interests in CPP as of January 1, 2005, accounted for a $1.1 million of the increase in gross margin. Profit on energy trading activities was $1.2 million for the nine months ended September 30, 2005 as compared to $1.7 million for the nine months ended September 30, 2004. The decrease in Profit from energy trading activities is primarily due to a volume decrease associated with contracts that were not renewed in 2005. In addition, a counterparty transaction was settled in the first quarter of 2004 which resulted in a positive adjustment to profit.

      During the first quarter of 2005 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 was $1.9 million for the nine months ended September 30, 2005. 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 was repaired and was back in service in April 2005.

      Treating gross margin was $28.1 million for the nine months ended September 30, 2005 compared to $18.5 million in the same period in 2004, an increase of $9.6 million, or 52%. The increase in treating plants in service from 67 plants at September 30, 2004 to 111 plants at September 30, 2005 contributed approximately $6.9 million to the increase in gross margin. Existing plant assets contributed $2.3 million in gross margin growth due primarily to plant expansion projects and increased volumes. The acquisition and installation of dew point control plants in 2005 contributed an additional $0.4 million to gross margin.

      Operating Expenses. Operating expenses were $37.6 million for the nine months ended September 30, 2005 compared to $26.7 million for the nine months ended September 30, 2004, an increase of $10.9 million, or 41%. An increase of $4.9 million was associated with the acquisition of the LIG assets. The growth in treating plants in service increased operating expenses by $4.0 million. Increased activity on various systems together with increases related to the acquisition of CPP and expansion at Arkoma and CDD contributed $2.0 million to the increase between nine month periods. Operating expenses included $0.3 million of stock-based compensation expense for the nine months ended September 30, 2005 compared to $0.2 million of stock-based compensation expense for the nine months ended September 30, 2004.

      General and Administrative Expenses. General and administrative expenses were $22.3 million for the nine months ended September 30, 2005 compared to $13.8 million for the nine months ended September 30, 2004, an increase of $8.5 million, or 62%. Compensation and office related expenses increased by $4.0 million due to staffing increases associated with the requirements of the LIG acquisition and growth in our treating business and our other assets as discussed above. Other variances include a $1.2 million increase in the bonus accrual during the third quarter of 2005 over the comparative quarter in 2004 because we expect to meet the bonus performance measures at a higher level than was previously accrued, a charge of $0.3 million for unsuccessful transaction costs, $0.4 million for Sarbanes-Oxley 404 compliance, $0.4 million for training and travel related costs, and $0.1 million for bad debt reserve. General and administrative expenses included $2.4 million of stock-based compensation expense for the nine months ended September 30, 2005 compared to

$0.6 million of stock-based compensation expense for the nine months ended September 30, 2004, accounting for a $1.8 million variance. Stock-based compensation expense during 2005 was higher than 2004 because $0.5 million of expense was recognized in the nine months ended September 30, 2005 related to the accelerated option vesting for two employees and due to additional option and restricted unit grants to a higher base of employees. The 10,000 CEI common share options, which were scheduled to vest on May 13, 2005, were accelerated to vest on April 1, 2005. Under the terms of the original option grant, these options expired on May 5, 2005, which was eight days before they vested due to an oversight in establishing the vesting date when these options were granted in May 2002. The vesting on the 7,060 Partnership unit options was accelerated for an employee who retired. Stock-based compensation expense included in general and administrative expense for the nine months ended September 30, 2005 also included $0.4 million of payroll taxes associated with CEI stock option exercises for which CEI contributed capital for the same amount to reimburse us.

      Gain/ Loss on Derivatives. The loss on derivatives was $13.7 million for the nine months ended September 30, 2005 compared to a profit of $0.2 million for the nine months ended September 30, 2004, a decrease of $13.9 million. Included in the nine months ended September 30, 2005 is a $2.4 million loss associated with derivatives for third party on-system financial transactions and storage financial transactions primarily due to the increase in commodity prices during the third quarter of 2005. We recognized gains due to the ineffectiveness of certain cash flow hedges of $0.3 million and an $11.5 million loss on puts acquired in the third quarter of 2005 related to the El Paso acquisition as discussed above under “Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004”.

      Gain/ Loss on Sale of Property. A gain of $8.0 million on the sale of an idle processing plant was recognized in the nine month period ending September 30, 2005. The gain was partially offset by a $0.2 million net loss on other small assets sold. Assets sold during 2005 did not significantly contribute to operating cash flows.

      Depreciation and Amortization. Depreciation and amortization expenses were $22.1 million for the nine months ended September 30, 2005 compared to $16.5 million for the nine months ended September 30, 2004, an increase of $5.6 million, or 34%. The new plants acquired from Graco in January 2005 and from Cardinal in May 2005, together with new treating plants placed in service, resulted in an increase of $2.1 million. The increase related to the LIG assets was $1.1 million. The remaining $2.4 million increase in depreciation and amortization is a result of other expansion projects.

      Interest Expense. Interest expense was $9.3 million for the nine months ended September 30, 2005 compared to $6.2 million for the nine months ended September 30, 2004, an increase of $3.1 million. The increase relates primarily to an increase in debt outstanding as a result of the LIG acquisition and other growth projects and higher interest rates between nine-month periods (weighted average rate of 6.3% in 2005 compared to 5.8% in 2004).

      Net Income. Net income for the nine months ended September 30, 2005 was $8.7 million compared to $17.6 million for the nine months ended September 30, 2004, a decrease of $8.9 million. The increase in gross margin of $25.9 million was partially offset by increases totaling $22.5 million in ongoing cash costs for operating expenses, general and administrative expenses and interest expense as discussed above. The increase in gross margin was further offset by increases in depreciation and amortization expenses totaling $5.6 million. Net income for the nine months was further impacted by the $8.0 million gain on disposition of an idle processing plant which was offset by a $13.7 million loss recorded on derivatives, including the $11.5 million loss on the puts associated with the El Paso acquisition.

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 provided by operating activities was $16.8 million for the nine months ended September 30, 2005 compared to $18.9 million for the nine months ended September 30, 2004. Income before non-cash income and expenses decreased by $9.2 million from $34.6 million in 2004 to $25.4 million in 2005,

primarily due to the $11.5 derivative million loss on the puts associated with the El Paso acquisition. Changes in working capital used $8.6 million in cash flows from operating activities in 2005 as compared to $15.7 million in cash flows provided by working capital changes in 2004. Our working capital deficit has increased in 2005 as discussed under “Working Capital Deficit” below.

      Net cash used in investing activities was $61.2 million and $100.1 million for the nine months ended September 30, 2005 and 2004, respectively. Net cash used in investing activities during 2005 related to the $9.3 million Graco acquisition, the $6.7 million Cardinal acquisition and $15.7 million related to the refurbishment and installation of additional treating plants. Costs associated with the connection of new wells to various systems, pipeline integrity projects, pipeline relocations and various other internal growth projects totaled $14.1 million, and costs related to the construction of the North Texas Pipeline project totaled $21.5 million for the nine months ended September 30, 2005. Expansion costs related to office space, measurement and accounting system installations and upgrades totaled $3.2 million in 2005. Investing activity in 2004 included $73.0 million for the LIG acquisition and $14.7 million for the purchase and installation of additional treating plants.

      Net cash provided by financing activities was $41.7 million for the nine months ended September 30, 2005 compared to $81.7 million provided by financing activities for the nine months ended September 30, 2004. Net proceeds from the issuance of approximately 1.5 million senior subordinated units in June 2005 provided cash of $51.1 million, including the general partner contribution. The proceeds were used to repay bank borrowings. Net bank borrowings of $32.0 million in the nine months ended September 30, 2005, net of the June 2005 repayment from the proceeds from the issuance of senior subordinated units, were used to fund the acquisitions and the internal growth projects discussed above. Distributions to partners totaled $31.6 million in the nine months ended September 30, 2005, compared to distributions in the nine months ended September 30, 2004 of $24.9 million. Drafts payable decreased by $10.8 million requiring the use of cash in the nine months ended September 30, 2005 as compared to an increase in drafts payable of $14.4 million providing cash from financing activities for the nine months ended September 30, 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.

      Working Capital Deficit. We had a working capital deficit of $41.2 million as of September 30, 2005, primarily due to drafts payable of $27.9 million and a net fair value of derivatives liability of $14.1 million. A net fair value of derivatives liability existed as of September 30, 2005 primarily due to the hedge accounting treatment for our cash flow hedges. In accounting for cash flow hedges the financial transactions that qualify as cash flow hedges are marked to market but the physical offset which is being hedged is not marked to market. Since we are hedging our “length” in the physical asset, the financial transaction is generally a liability. Due to the major increases in natural gas and natural gas liquids prices during the three months ended September 30, 2005, and to increases in our hedge position, the financial liability has increased significantly. The profit and loss impact of these transactions is recognized when the physical commodity being hedged is settled. Until that time, the profit and loss impacts are reflected as an adjustment to Other Comprehensive Income in Partners’ Equity.

      As discussed under “Cash Flows” above, in order to reduce our interest costs we do not borrow money to fund outstanding checks until they are presented to our bank which causes the working capital deficit associated with drafts payable. We borrow money under our credit facility to fund checks as they are presented.

      June 2005 Sale of Senior Subordinated Units. In June 2005, we issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including our general partners’ $1.1 million capital contribution. The senior subordinated units were issued at $33.44 per unit, which represents a discount of 13.7% to the market value of common units on such date, and will automatically convert to common units on a one-for-one basis on February 24, 2006. The senior subordinated units will receive no distributions until their conversion to common units.

      November 2005 Sale of Senior Subordinated B Units. On November 1, 2005, we issued 2,850,165 Senior Subordinated Series B Units in a private placement for a purchase price of $36.84 per unit. We received net proceeds of approximately $107 million, including our general partner’s $2 million capital contribution and expenses associated with the sale. The Senior Subordinated Series B Units will automatically convert into common units on November 14, 2005 at a ratio of one common unit for each Senior Subordinated Series B Unit.

The Senior Subordinated Series B Units will not be entitled to distributions of available cash until they convert into common units.

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

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

      We believe that cash generated from operations will be sufficient to meet our present quarterly distribution level of $0.49 per quarter and to fund a portion of our anticipated capital expenditures through September 30, 2006. Total capital expenditures are budgeted to be approximately $70 million (excluding the assets acquired from El Paso) for the remainder of 2005, including $65 million for the North Texas Pipeline project. We expect to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below”. Our ability to pay distributions to our unit holders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

      See “Subsequent Events” for discussion of the November 1, 2005 acquisition of assets from El Paso.

      Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2005.

Indebtedness

      As of September 30, 2005 and December 31, 2004, long-term debt consisted of the following (in thousands):

      On March 31, 2005, we amended our 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. On November 1, 2005, we amended our bank credit facility to, among other things, provide for revolving credit borrowings up to a maximum principal amount of $750 million at any one time outstanding and the issuance of letters of credit in the aggregate face amount of up to $300 million at any one time outstanding, which letters of credit reduce the credit available for revolving credit borrowings. The bank credit agreement includes procedures for additional financial institutions selected by us to become lenders under the agreement, or for any existing lender to increase its commitment in an amount

approved by us and the lender, subject to a maximum of $300 million for all such increases in commitments of new or existing lenders.

      Under the amended credit agreement, borrowings bear interest at our option at the administrative agent’s reference rate plus 0% to 0.50% or LIBOR plus 1.00% to 2.00%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.00% to 2.00% 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:

      In June 2005, we further amended our Shelf Agreement for our senior secured notes increasing our availability from $125 million to $200 million.

      We were in compliance with all debt covenants at September 30, 2005 and expect to be in compliance for the next twelve months.

      Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2005, is as follows:

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

      The unconditional purchase obligations for 2005 relate to the purchase of pipe for the construction of our North Texas Pipeline which began in September 2005.

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 21E 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, and 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 such as “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.

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. In addition, a portion of our loss at certain processing operations is denominated in natural gas liquids. We also incur credit risks and risks related to interest rate variations.

      Commodity Price Risk. Approximately 11% 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 72% of our exposure to gas price fluctuations through the end of 2005 and 75% of our exposure to gas price fluctuations for the first half of 2006 and 80% for the second half of 2006. We have also hedged approximately 80% of our exposure to liquids price fluctuations through the end of 2005 and 2006.

      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 and natural gas liquids 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.

      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. As of September 30, 2005, outstanding natural gas swap agreements, natural gas liquids swap agreements, swing swap agreements, storage swap agreements, natural gas liquids puts and other derivative instruments had a net fair value liability of $8.4 million. The aggregate effect of a hypothetical 10% increase in gas and natural gas liquids prices would result in a change of approximately $3.5 million in the fair value of these contracts as of September 30, 2005.

      Concentration Risk. The counterparties to substantially all of the Partnership’s derivative contracts as of September 30, 2005 were BP Corporation and J. Aron & Co., a subsidiary of Goldman Sachs. Although we do not believe we have a counterparty risk with either party, our loss would be substantial if BP Corporation or J. Aron & Co. were to default.

      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 September 30, 2005, we had $65.0 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 $0.7 million 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 September 30, 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 processes 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.

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 September 30, 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 September 30, 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 8th day of November, 2005.

EXHIBIT INDEX