Back to GetFilings.com




Use these links to rapidly review the document
TABLE OF CONTENTS



SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K


ý

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2002

OR

o

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from                            to                             

Commission file number: 000-50067

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

Delaware
(State of organization)
  16-1616605
(I.R.S. Employer Identification No.)

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

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

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

Title of Each Class
  Name of Exchange on which Registered
None   Not applicable

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

Title of Class
Common Units Representing Limited Partnership Interests

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

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

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

        The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $48,524,500 on December 31, 2002, based on $21.40 per unit, the closing price of the Common Units as reported on the NASDAQ National Market on such date.

        At March 4, 2003, there were outstanding 2,633,000 Common Units and 4,667,000 Subordinated Units.

DOCUMENTS INCORPORATED BY REFERENCE: None.




TABLE OF CONTENTS
DESCRIPTION

Item

   
PART I

1.

 

BUSINESS
2.   PROPERTIES
3.   LEGAL PROCEEDINGS
4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

PART II

5.

 

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
6.   SELECTED FINANCIAL DATA
7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

PART III

10.

 

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
11.   EXECUTIVE COMPENSATION
12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
14.   CONTROLS AND PROCEDURES

PART IV

15.

 

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K

i



CROSSTEX ENERGY, L.P.

PART I


Item 1. Business

General

        Crosstex Energy, L.P. (the "Registrant" or "Partnership") is a publicly traded Delaware limited partnership, formed in July 2002 in connection with its initial public offering, which was completed in December 2002. Our Common Units are listed on the NASDAQ National Market. Our business activities are conducted through our subsidiary, Crosstex Energy Services, L.P., a Delaware limited partnership (the "Operating Partnership") and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our telephone number is (214) 953-9500. In this report, the terms "Partnership" and "Registrant," as well as the terms "our," "we," and "its," are sometimes used as abbreviated references to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. and its consolidated subsidiaries, including the Operating Partnership.

        We are primarily engaged in the midstream energy business focused on the gathering, transmission, treating, processing and marketing of natural gas. We connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities to ensure that it meets pipeline quality specifications, process natural gas for the removal of natural gas liquids or NGLs, transport natural gas and ultimately provide an aggregated supply of natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generate gross margins based on the difference between the purchase and resale prices. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee.

        Our major assets include over 1,700 miles of natural gas gathering and transmission pipelines, one natural gas processing plant (the "Gregory plant") connected to our Gregory gathering system, a smaller gas processing plant (the "Masters Creek plant") and 49 natural gas treating plants. Our gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plants remove NGLs from a natural gas stream and, in the case of the Gregory Plant, fractionates, or separates, the NGLs into separate NGL products, including ethane, propane, mixed butanes and natural gasoline. Our natural gas treating plants, located largely in the Texas Gulf Coast area, remove impurities from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications.

        We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. See Note Thirteen to the consolidated financial statements for financial information about these business segments.

        Our general partner interest is held by Crosstex Energy GP, L.P., a Delaware limited partnership. Crosstex Energy GP, LLC, a Delaware limited liability company, is Crosstex Energy GP, L.P.'s general partner. Crosstex Energy GP, LLC manages our operations and activities and employs our officers.

1



        References in this report to "our predecessor" refer to Crosstex Energy Services, Ltd., a Texas limited partnership, substantially all of the assets of which were transferred to the Partnership at the closing of our initial public offering.

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

        Gathering and Transmission.    Our natural gas gathering and transmission operations include over 1,700 miles of pipeline. We own a cryogenic gas processing facility with full liquid fractionation capabilities that is located on one of our major gathering systems north of Corpus Christi, Texas. For the year ended December 31, 2002, we gathered and transported approximately 368,177 Mcf/d of natural gas. Set forth below is a discussion of our principal pipeline systems.

2


        Producer Services.    We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 50 independent producers. We engage in such activities on more than 30 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.

        Our business strategy includes developing relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business also provides us with strategic insights and valuable market intelligence which may impact our expansion and acquisition strategy.

3



        We offer to our customers the ability to hedge their purchase or sale price by agreeing to sell to us or to purchase from us volumes of natural gas. This risk management tool enables our customers to reduce pricing volatility associated with the sale and purchase of natural gas. When we agree to purchase or sell natural gas from a customer, we contemporaneously execute a contract for the sale or purchase of such natural gas or we enter into an offsetting obligation using futures contracts on the New York Mercantile Exchange or by using over-the-counter derivative instruments with third parties.

        We operate treating plants which remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications. The plants we operate are primarily amine plants. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb the impurities from the gas. After mixing, gas and amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute. Our hydrogen sulfide scavenger facilities use a liquid or solid chemical that reacts with hydrogen sulfide thereby removing it from the gas. Used chemicals are disposed of and cannot be regenerated as amine can. In addition, our membrane plants use a molecular filter to separate carbon dioxide and hydrogen sulfide from natural gas.

Business Strategy

        Our strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation, and marketing of natural gas; improving the profitability of our owned assets by increasing their utilization while controlling costs; accomplishing economies of scale through new construction or expansion in core operating areas; and maintaining financial flexibility to take advantage of opportunities. Our strategy is based on our expectation of a continued high level of drilling in our principal geographic areas and a process of ongoing divestitures of gas transportation and processing assets by large industry participants. We believe these two factors should present opportunities for continued expansion in our existing areas of operation as well as opportunities to acquire assets in new geographic areas that may serve as a platform for future growth. Key elements of our strategy include the following:

4


Recent Acquisitions and New Construction

        In December 2002, we acquired the Vanderbilt System from Devon Energy Corporation for $12.0 million, and the 50% operating interest in a treating plant (the Will-O-Mills plant) in which we already owned a 50% non-operating interest, for $2.2 million. We also recently formed a joint venture to construct a gathering system in an area of the Barnett Shale gas play at an initial cost of $3.0 million. See Item 2. "Properties."

Industry Overview

        The following diagram illustrates the natural gas treating, gathering, processing, fractionation and transmission process.

GRAPHIC

        The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

        Natural gas gathering.    The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary,

5



compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

        Natural gas treating.    Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide. Treating plants are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems to ensure that it meets pipeline quality specifications.

        Natural gas processing and fractionation.    The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Natural gas is described as dry or wet depending on its NGL content. These are relative terms, but as generally used, a wet gas may contain two gallons or more of NGLs per Mcf, whereas a dry gas usually contains less than one gallon of recoverable liquids per Mcf. Most wet natural gas is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with NGLs and contaminants removed to very low concentrations. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.

        Natural gas transmission.    Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, plant tailgates, and gathering systems and deliver it to industrial end-users, utilities and to other pipelines.

Risk Management

        It is our policy that as we purchase natural gas, we establish a margin by selling natural gas for physical delivery to third-party users. We seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes. For that portion of the gas we purchase which we buy on a percentage-of-index or percentage-of-proceeds contracts, since our margin can vary with the price of natural gas, we may hedge our margin. We also enter into similar contracts to hedge prices on behalf of producers we serve, using over-the-counter derivative instruments or by entering into a future delivery obligation under futures contracts on the New York Mercantile Exchange.

Competition

        The business of providing natural gas gathering, transmission, treating, processing and marketing services is highly competitive. We face strong competition in acquiring new natural gas supplies. Our competitors in obtaining additional gas supplies and in treating new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors in the Texas Gulf Coast area for natural gas supplies and markets include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services.

        Our gas treating operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant leasing and operations similar to ours. We also face competition from vendors of used equipment that occasionally lease and operate plants for

6



producers. Our primary competitor for natural gas treating services in our principal market area is The Hanover Company.

        In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

Natural Gas Supply

        Our end-user pipelines have connections with major interstate and intrastate pipelines, which we believe have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of our gathering systems, we evaluated well and reservoir data furnished by producers to determine the availability of natural gas supply for the systems. Based on those evaluations, we believe that there should be adequate natural gas supply to recoup our investment with an adequate rate of return. We do not routinely obtain independent evaluations of reserves dedicated to our systems due to the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such producing reserves.

Regulation

        Intrastate Pipeline Regulation.    Our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies of the states in which they are located, principally the Texas Railroad Commission. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.

        Our operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates.

        Pipeline Integrity Rules recently implemented by the TRRC require a pipeline operator to prove operational safety of a pipeline segment on a periodic basis. The rules offer two methods of proving a pipeline's integrity; Direct (Risk-Based) Assessment or Prescriptive Testing. Risk-Based Assessment proves a pipeline's integrity through documentation (including construction, testing and operating records) and Prescriptive Testing proves integrity through physical testing (an in-line inspection or hydrostatic pressure test). Crosstex intends to use the Risk-Based Assessment method to achieve full compliance in a cost effective manner in conjunction with Prescriptively Testing of pipeline segments in high consequence areas.

        Gathering Pipeline Regulation.    Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the

7



classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.

        We are subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

        Sales of Natural Gas.    The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. FERC is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations. Some of FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Environmental Matters

        General.    Our operation of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionization and storage of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to release of hazardous substances or wastes into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing, and operating our plants, pipelines, and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities.

        Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays.

        Hazardous Substance and Waste.    The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third

8



parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although "petroleum" as well as natural gas and NGLs are excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous state laws.

        We also generate both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the Environmental Protection Agency, or EPA, has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes.

        We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination.

        Air Emissions.    Our operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. Such requirements, if applicable to our operations, could cause us to incur capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of our facilities. Although we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

        Clean Water Act.    The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.

        Employee Safety.    We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our

9



operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

        Safety Regulations.    Portions of our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements.

Office Facilities

        In addition to our gathering and treating facilities discussed above, we occupy approximately 17,000 square feet of space at our executive offices in Dallas, Texas under a lease expiring in November 2004.

Employees

        As of December 31, 2002, our operating partnership, Crosstex Energy Services, L.P., had approximately 126 full-time employees. Approximately half of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.

10



Item 2. Properties

        Set forth in the table below is a list of our significant acquisitions since January 2000.

Acquisition

  Acquisition
Date

  Purchase
Price
(in thousands)

  Asset Type
  Average
Throughput
at Time of Acquisition
(MMBtu/d)

  Average
Throughput
for Year Ended
December 31, 2002
(MMBtu/d)

 
Provident City Plant   February 2000   $ 350   Treating plants   3,000   29,442  

Will-O-Mills

 

February 2000

 

 

2,000

 

Treating plants

 

11,800

 

11,586

 

Arkoma Gathering System

 

September 2000

 

 

10,500

 

Gathering pipeline

 

12,000

 

10,785

 

Gulf Coast System

 

September 2000

 

 

10,632

 

Gathering and transmission pipeline

 

117,000

 

103,323

 

CCNG acquisition

 

May 2001

 

 

30,003

 

Gathering and transmission pipeline and processing plant

 

358,000

 

348,085

 

Pettus Gathering System

 

June 2001

 

 

450

 

Gathering system

 


 


 

Millennium Gas Services

 

October 2001

 

 

2,124

 

Treating assets

 


 


 

Florida Gas Transmission

 

June 2002

 

 

2,300

 

Pipeline segment

 


 


 

Pandale System

 

June 2002

 

 

2,000

 

Gathering pipeline

 

17,000

 


(1)

KCS McCaskill Pipeline

 

June 2002

 

 

250

 

Pipeline segment

 


 


 

Vanderbilt Pipeline

 

December 2002

 

 

12,000

 

Transmission pipeline

 

32,000

 


(1)

Will-O-Mills

 

December 2002

 

 

2,235

 

Treating plant

 

10,590

 


(1)

(1)
Acquired during 2002.

Midstream Division

        Our primary Midstream assets are four major systems and a natural gas processing plant along the Texas Gulf Coast and one gathering system in eastern Oklahoma, which in the aggregate consist of approximately 1,700 miles of gathering and transmission pipelines. For the year ended December 31,

11



2002, we gathered and transported approximately 368,177 Mcf/d of natural gas. Certain information regarding our primary assets in our Midstream division is summarized in the table below:

 
   
   
   
  Year Ended
December 31, 2002

 
Asset

  Type
  Length
(miles)

  Throughput
Capacity
(Mcf/d)

  Average
Throughput
(Mcf/d)

  Utilization
of Capacity

 
Gulf Coast system   Gathering and transmission pipelines   484   200,000   98,123   49.1 %

Corpus Christi system

 

Gathering and transmission pipelines

 

295

 

350,000

 

155,279

 

44.4

%

Gregory gathering system(1)

 

Gathering pipelines

 

297

 

200,000

 

95,984

 

48.0

%

Gregory processing plant

 

Processing and fractionation facility

 

N/A

 

80,000

 

75,337

 

94.2

%

Arkoma gathering system

 

Gathering pipelines

 

100

 

20,000

 

10,080

 

50.4

%

Vanderbilt pipeline

 

Transmission pipeline

 

200

 

130,000

 

30,095

 

23.2

%

Other systems

 

Gathering and transmission pipelines

 

330

 

319,400

 

63,828

 

20.0

%

 

 

 

 



 

 

 

 

 

 

 
 
Total

 

 

 

1,706

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

(1)
The throughput on our Gregory gathering system is limited by the processing capacity of the Gregory processing plant, which is currently 85,000 Mcf/d, and a by-pass around the Gregory processing plant which has a capacity of 30,000 Mcf/d.

        Gulf Coast System.    The Gulf Coast system is an intrastate pipeline system consisting of approximately 484 miles of gathering and transmission pipelines with a mainline from Refugio County in south Texas running northeast along the Gulf Coast to the Brazos River in Fort Bend County near Houston. The system's gathering and transmission pipelines range in diameter from 4 to 20 inches. We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million.

        The Gulf Coast system has two supply pipeline laterals which connect to gathering systems which collect natural gas from approximately 76 receipt points and five treating and processing plants operated by third parties. This system has three delivery laterals—an 8 inch lateral into the Victoria area, a 12 inch lateral into the Point Comfort area, and a 16 inch lateral into the Bay City area—which deliver natural gas directly to large industrial and utility consumers along the Gulf Coast. The system interconnects with multiple third-party pipelines through which we may purchase volumes not gathered through our systems for resale or through which we might deliver natural gas to customers which are not connected to our system. We also hold firm transportation capacity on the TXU Lone Star pipeline, which provides access for our Gulf Coast mainline system in Fort Bend County to the Katy hub, a major natural gas physical exchange that allows access to seven third-party pipelines, including Kinder Morgan, TECO and Trunkline. The Gulf Coast system had average throughput of approximately 103,323 MMBtu/d for the year ended December 31, 2002.

        Vanderbilt System.    On December 19, 2002, we acquired the Vanderbilt System from a subsidiary of Devon Energy Corporation. The Vanderbilt system has approximately 200 miles of gathering pipeline located near our Gulf Coast system. The purchase price was $12.0 million. The pipeline ranges in diameter from 4 to 14 inches and had throughput at the time of acquisition of approximately 32,000 MMBtu/d. Gathered natural gas currently flows to the Exxon Katy plant, which is scheduled to close in November 2003. We have a contract to deliver the natural gas from this gathering system to the Formosa Hydrocarbons processing plant at Point Comfort, Texas beginning in the spring of 2003.

12



        Corpus Christi System.    The Corpus Christi system is an intrastate pipeline system consisting of approximately 295 miles of gathering and transmission pipelines and extends from supply points in south Texas to markets in Corpus Christi, Texas. Its gathering and transmission pipelines range in diameter from 4 to 20 inches. We acquired the Corpus Christi system in May 2001 in conjunction with the acquisition of the Gregory gathering system and Gregory processing plant, (the CCNG Acquisition), for an aggregate purchase price of approximately $30 million. The main lines comprising the Corpus Christi system were constructed in the 1940's with additional expansions throughout the 1990's. We believe the expected remaining life of the pipeline system is approximately 50 years.

        Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 12 treating and processing plants and third-party gathering systems and pipelines. The system interconnects with multiple third-party pipelines through which we may purchase volumes not gathered through our systems for resale or through which we may deliver natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system had an average throughput of approximately 157,918 MMBtu/d for the year ended December 31, 2002.

        In June 2002, we acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows us access to the Florida Gas transmission mainline and accordingly the ability to reach markets in Florida. We have constructed an addition to this transmission line creating a connection between our Gulf Coast system and our Corpus Christi system. This connection allows us to transport gas between our two systems, thereby reducing our dependence on third-party suppliers, move gas supplies to more favorable markets and enhance our margins. In December, 2002, after completion of the interconnect between our systems and Florida Gas Transmission Company, we sold an average daily quantity of 43,000 MMBtu/d into the Florida markets.

        Gregory Gathering System.    We acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the CCNG Acquisition. The plant and the gathering system are located north of Corpus Christi, Texas. The gathering system is connected to approximately 70 receipt points in San Patricio County, the Corpus Christi Bay area, Mustang Island, and adjacent coastal areas. The gathering system consists of approximately 297 miles of pipeline ranging in diameter from 2 inches to 18 inches. Until early 2002, all of the gas from the gathering system had been delivered to the inlet of the processing plant. Accordingly, the capacity of the gathering system was constrained by the inlet capacity of the plant. In January 2002, we constructed a by-pass around the plant so that additional gas can be delivered to the plant tailgate without processing. The gathering system had average throughput of approximately 106,543 MMBtu/d for the year ended December 31, 2002 compared to approximately 76,500 MMBtu of gas per day at the time of our acquisition. The Gregory gathering system was constructed in the 1980's and we believe the expected remaining life of the pipeline system is approximately 50 years.

        Gregory Processing Plant.    Our Gregory processing plant is a cryogenic turbo-expander with a 210,000 gallon per day fractionator that removes liquid hydrocarbons from the liquids-rich gas produced into the Gregory gathering system. Our Gregory processing plant had an average throughput of approximately 83,624 MMBtu/d for the year ended December 31, 2002. At the time of our acquisition, the plant was processing approximately 86,247 MMBtu of gas per day. The Gregory processing plant was constructed in the 1980's and expanded and upgraded in 1998. We believe the expected remaining life of the Gregory processing plant is approximately 20 years. As part of the CCNG Acquisition, we entered into a contract whereby all of the processed natural gas coming from our Gregory processing plant is sold to a subsidiary of Kinder Morgan under a contract that expires in March, 2006.

        Arkoma Gathering System.    We acquired the Arkoma gathering system, located in the Southeastern region of Oklahoma, in September 2000 for $10.5 million. In addition, since acquiring this system, we have acquired the Shawnee extension, consisting of 15 miles of gathering pipelines extending through additional supply areas in this region. The Arkoma gathering system when acquired was approximately

13



84 miles in length and included a 3,700 horsepower compressor station. With the addition of the Shawnee extension and additional well connections, the system is now approximately 100 miles in length and ranges in diameter from 2 to 10 inches. This low-pressure system gathers gas from approximately 146 wells to three compressor stations for discharge to a mainline transmission pipeline. This system had average throughput of approximately 10,785 MMBtu/d for the year ended December 31, 2002.

        Other Systems.    We own several small gathering systems totaling approximately 330 miles, including our Manziel system in Wood County, Texas, our San Augustine system in San Augustine County, Texas, our Freestone Rusk system in Freestone County, Texas, and our Jack Starr and North Edna systems in Jackson County, Texas. Through Crosstex Pipeline Partners, a limited partnership of which we are the co-general partner, we own a 28% interest in five gathering systems in east Texas, totaling 64 miles. We also own five industrial bypass systems each of which supplies natural gas directly from a pipeline to a dedicated customer. The combined volumes for these five industrial bypass systems was approximately 4,900 MMBtu/d for the year ended December 31, 2002. In addition to these systems, we own various smaller gathering and transmission systems located in Texas and New Mexico.

Treating Division

        As of December 31, 2002, we owned 49 treating plants, 26 of which were operated by our personnel, 9 of which were operated by producers, and 14 of which were held in inventory. We entered the treating business in 1998 with the strategic acquisition of WRA Gas Services. In October 2001, we completed our largest acquisition of gas treating assets with the acquisition of Millenium Gas Services, which added 11 treating plants, four of which were in operation and seven of which were placed in our inventory.

        The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced to transportation systems to ensure that it meets pipeline quality specifications. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide. The majority of our active plants are treating gas from the Wilcox and Edwards formations, both of which are deeper formations that are high in carbon dioxide. Our active treating facilities include 33 amine plants and two hydrogen sulfide scavenger installations. In cases where producers pay us to operate the treating facilities, we either charge a fixed rate per Mcf of natural gas treated or charge a fixed monthly fee. If the producer operates the facility, we receive a fixed monthly fee.

        In addition to our treating plants, we have three gathering systems in our treating division with an aggregate of 43 miles of gathering pipeline located in Val Verde, Crockett, Dewitt and Live Oak counties, Texas that are connected to approximately 73 producing wells. These gathering systems are connected to three of our treating plants, including the Will-O-Mills plant in Val Verde County, Texas, which we consolidated ownership of in December 2002. The diameter of these gathering pipelines ranges from 2 to 6 inches. These gathering assets in the aggregate had average throughput of approximately 23,396 MMBtu/d for the year ended December 31, 2002. In cases where we both gather and treat natural gas, our fee is generally based on throughput.

        A component of our strategy is to purchase used plants and then refurbish and repair them at our shop and seven-acre yard in Victoria, Texas and our 14-acre yard in Odessa, Texas. We believe that we can purchase used plants and recondition them at a significant cost savings to purchasing new plants. We have an inventory of plants of varying sizes which can be deployed after refurbishment. We also mount most of the plant equipment on skids allowing them to be moved in a timely and cost efficient manner. At such time as our active plants come offline, we put them in our inventory pending redeployment. We believe our plant inventory gives us an advantage of several weeks in the time required to respond to a producer's request for treating services.

14



Title to Properties

        Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our Gregory processing plant is on land that we own in fee.

        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, our general partner believes that these consents, permits or authorizations will be obtained or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

        Our general partner believes that we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by affiliates of our predecessor until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. Our general partner believes that none of such encumbrances should materially detract from the value of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business.


Item 3. Legal Proceedings

        We are not currently a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverage and deductibles as the managing general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.


Item 4. Submission of Matters to a Vote of Security Holders

        No matters were submitted to security holders during the fourth quarter of the year ended December 31, 2002.

15



PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

        The Partnership's common units representing limited partner interests in the Partnership are listed on the NASDAQ National Market under the symbol "XTEX". The common units began trading on December 12, 2002, at an initial public offering price of $20.00 per common unit. On March 4, 2003, the market price for the common units was 23.95 per unit and there were approximately 2,610 record holders and beneficial owners (held in street name) of the Partnership's common units and one record holder of the Partnership's subordinated units. There is no established public trading market for the Partnership's subordinated units.

        The following table sets forth, for the portion of the fourth quarter 2002 in which the common units were traded, the range of high and low closing sales prices for the common units as reported by the NASDAQ National Market, and the amount of cash distribution paid per common unit for the portion of the fourth quarter 2002 commencing December 17, 2002, the date of closing of the initial public offering.

 
  Common Unit Price Range
   
 
  Cash Distribution Paid Per Unit
 
  High
  Low
2002:                  
  4th Quarter   $ 21.75   $ 19.46   $ 0.00

        The Partnership has also issued subordinated units representing limited partner interests in the Partnership, all of which are held by an affiliate of the general partner, for which there is no established public trading market.

        Beginning with the quarter ending March 31, 2003, we will distribute, on a quarterly basis, all of our available cash. Available cash generally means, for any of our fiscal quarters, all cash on hand at the end of the quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to:

        Minimum quarterly distributions are $0.50 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. We will adjust the minimum quarterly distribution for our initial distribution by approximately $.07 for the period from the closing of our initial public offering on December 17, 2002 through March 31, 2003.

        The subordination period will end if certain financial tests contained in the partnership agreement are met for three consecutive four-quarter periods (the "testing period"), but no sooner than December 31, 2007. During the first quarter after the end of the subordination period, all of the subordinated units will convert into Common Units. Early conversion of a portion of the subordinated units may occur if the financial tests are satisfied before December 31, 2007.

        In addition to distributions on its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally

16



our general partner is entitled to 13% of amounts we distribute in excess of $0.50 per unit, 23% of the amounts we distribute in excess of $0.625 per unit and 48% of amounts we distribute in excess of $0.75 per unit.

        Under the terms of our bank credit agreement and letter of credit and borrowing facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. "Management's Discussion and Analysis—Liquidity and Capital Resources."

Recent Sales of Unregistered Securities

        On December 17, 2002 and in offerings exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, the Partnership converted the existing limited partner interest in the Partnership owned by Crosstex Energy Holdings Inc. into 333,000 common units and 4,667,000 subordinated units in connection with the contribution of the interests of our subsidiaries which hold our operating assets. There have been no other sales of unregistered securities of the Partnership within the past three years.

Use of Proceeds From Registered Securities

        On December 12, 2002, the Partnership's registration statement on Form S-1 (Registration No. 333-97779) was declared effective by the Securities and Exchange Commission in connection with the public offering of 2,000,000 common units representing limited partner interests in the Partnership (plus up to 300,000 additional common units upon the exercise of the underwriters' over-allotment option), which commenced on December 17, 2002. The initial public offering did not terminate prior to the sale of all the securities registered. The underwriters of the offering were A. G. Edwards & Sons, Inc., Raymond James & Associates, Inc., and RBC Dain Rauscher Inc. The initial public offering consisted solely of the one class of common units. The number of securities registered, including the Common Units subject to the underwriters' over-allotment option, was 2,300,000, all of which have been sold to the public.

        The price to public, underwriting discounts and commissions, and proceeds to the Partnership are set forth in the following table:

 
  Price to Public
  Underwriting
Discounts and
Commissions

  Proceeds to the
Partnership (1)

Per common unit   $ 20.00   $ 1.40   $ 18.60
Total upon initial public offering   $ 40,000,000   $ 2,800,000   $ 37,200,000
Total upon exercise of over-allotment   $ 46,000,000   $ 3,220,000   $ 42,780,000

(1)
Before deducting expenses of $2.59 million paid by the Partnership.

        The net proceeds of the initial public offering of the common units, after deducting expenses of $2.59 million and underwriting discounts and commissions of $3.22 million, was $40.19 million. The Partnership distributed $2.50 million of the net proceeds from the sale of the common units in the initial public offering and the exercise of the underwriters' over-allotment to Crosstex Energy Holdings Inc., pursuant to the terms of the partnership agreement of the Partnership. The Partnership contributed the remainder of such net proceeds ($37.69 million) to the Operating Partnership. Net proceeds from the sale of common units in the initial public offering were used by the Operating Partnership to repay $33.00 million of outstanding borrowings under our existing credit facility, which replaced our predecessor's credit facility, and the remaining $4.69 million was added to the working capital of the Operating Partnership.

17



        For additional information regarding the terms of the our existing credit facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."


Item 6. Selected Financial Data

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

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

18


 
  Crosstex Energy, L.P.
  Crosstex Energy Services, Ltd.(1)
 
 
  Year Ended
December 31, 2002

  Year Ended
December 31, 2001

  Eight Months
Ended
December 31, 2000

  Four Months
Ended April 30, 2000

  Year Ended
December 31, 1999

  Year Ended
December 31, 1998

 
Statement of Operations Data:                                      
  Revenues:                                      
    Midstream   $ 437,676   $ 362,673   $ 88,008   $ 3,591   $ 7,896   $ 7,181  
    Treating     14,817     24,353     17,392     5,947     9,770     1,647  
   
 
 
 
 
 
 
      Total revenues     452,493     387,026     105,400     9,538     17,666     8,828  
   
 
 
 
 
 
 
  Operating costs and expenses:                                      
    Midstream purchased gas     413,982     344,755     83,672     2,746     5,154     5,561  
    Treating purchased gas     5,767     18,078     14,876     4,731     8,110     1,025  
    Operating expenses     10,468     7,430     1,796     544     986     871  
    General and administrative     8,454     5,914     2,010     810     2,078     2,006  
    Stock based compensation     41             8,802          
    Impairments     4,175     2,873             538      
    (Profit) loss on energy trading contracts     (2,703 )   3,714     (1,253 )   (638 )   (1,764 )   (1,402 )
    Depreciation and amortization     7,745     6,101     2,261     522     1,286     843  
   
 
 
 
 
 
 
      Total operating costs and expenses     447,929     388,865     103,362     17,517     16,388     8,904  
   
 
 
 
 
 
 
    Operating income (loss)     4,564     (1,839 )   2,038     (7,979 )   1,278     (76 )
   
 
 
 
 
 
 
    Other income (expense):                                      
      Interest expense, net     (2,717 )   (2,253 )   (530 )   (79 )   (638 )   (502 )
      Other income (expense)     155     174     115     381     (138 )   88  
   
 
 
 
 
 
 
        Total other income (expense)     (2,562 )   (2,079 )   (415 )   302     (776 )   (414 )
   
 
 
 
 
 
 
    Net income (loss)   $ 2,002   ($ 3,918 ) $ 1,623   ($ 7,677 ) $ 502   ($ 490 )
   
 
 
 
 
 
 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Working capital surplus (deficit)     (8,672 )   (2,254 )   5,861     (4,005 )   (3,483 )   (3,394 )
  Property and equipment, net     109,948     84,951     37,242     10,540     8,072     10,103  
  Total assets     232,438     168,376     201,268     45,051     36,497     37,223  
  Long-term debt     22,550     60,000     22,000     7,000     5,389     6,589  
  Partners' equity     89,816     41,155     40,354     3,608     3,242     2,655  
  Cash Flow Data:                                      
  Net cash flow provided by (used in):                                      
    Operating activities   $ 19,956   $ (8,326 ) $ 7,741   $ 7,380   $ 1,404   $ 3,963  
    Investing activities     (33,240 )   (52,535 )   (25,643 )   (2,849 )   (1,342 )   (4,821 )
    Financing activities     14,240     42,558     36,557     198     (857 )   1,437  
  Operating Data:                                      
  Pipeline throughput (MMBtu/d)     392,608     313,103     104,185     23,098     19,712     16,435  
  Natural gas processed (MMBtu/d)     85,581     60,629     15,661     30,699     23,112     13,394  
  Treating volumes (MMBtu/d)(2)     97,033     62,782     35,910     26,872     12,896     3,982  

(1)
Crosstex Energy Services, Ltd. is the predecessor to Crosstex Energy, L.P. Results of operations and balance sheet data prior to May 1, 2000 represent historical results of the predecessor to Crosstex Energy Services, Ltd. These results are not necessarily comparable to the results of Crosstex Energy Services, Ltd. subsequent to May 2000 due to the new basis of accounting.
(2)
Represent volumes for treating plants operated by us whereby we receive a fee based on the volumes treated.

19



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

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

Overview

        We are a Delaware limited partnership formed by Crosstex Energy Holdings Inc. on July 12, 2002 to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the year ended December 31, 2002, 73% of our gross margin was generated in the Midstream division, with the balance in the Treating division, and approximately 86% of our gross margin was generated in the Texas Gulf Coast region.

        Since our formation, we have grown significantly as a result of our construction and acquisition of gathering and transmission pipelines, treating and processing plants. From January 1, 2000 through December 31, 2002, we have invested approximately $115.1 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. We generate revenues from four 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. We attempt to execute all purchases and sales substantially concurrently. 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.

        Set forth in the table below is the volume of the natural gas purchased and sold at a fixed discount or premium to the index price and at a percentage discount or premium to the index price for our

20



principal gathering and transmission systems and for our producer services business for the year ended December 31, 2002.

 
  Year Ended December 31, 2002

 
  Gas Purchased
  Gas Sold
Asset or Business

  Fixed Amount to Index
  Percentage of Index
  Fixed Amount to Index
  Percentage of Index
 
  (in billions of MMBtus)

Gulf Coast system   34.7   3.0   37.7  
Corpus Christi system   54.6   0.3   54.9  
Gregory gathering system (1)   35.8   3.2   31.9  
Arkoma gathering system     3.9   3.9  
Producer services (2)   81.2   2.9   84.1  

(1)
Gas sold is less than gas purchased due to production of natural gas liquids.
(2)
These volumes are not reflected in revenues or purchased gas cost, but are presented net as a component of profit (loss) on energy trading contracts in accordance with EITF 02-03.

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

        We generate producer services revenues through the purchase and resale of natural gas. We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 50 independent producers. We engage in such activities on more than 30 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:

21


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

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

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

        Crosstex Energy Holdings Inc. modified certain terms of certain outstanding options in the first quarter of 2003. These modifications will result in variable award accounting for the modified options. Based on an assumed unit value of $23 per unit, total compensation expense would be approximately $2.2 million, which will be recorded by Crosstex Energy, L.P. as non-cash stock based compensation expense in the first quarter of 2003. Compensation expense in future periods will be adjusted for changes in the unit market price.

        As described in the historical financial statements, the investment in our predecessor by Yorktown Energy Partners IV, L.P. in May 2000 resulted in the dissolution of the predecessor partnership, and the creation of a new partnership with the same organization, purpose, assets, and liabilities. The transaction value of $21.9 million from the Yorktown investment was allocated to the assets and liabilities of our predecessor, which created increases in depreciation and amortization charges in periods subsequent to the Yorktown investment. The historical financial statements present separate reports for the entities before and after the transaction. For purposes of the analysis below, the year 2000 is considered one period, and the distinction in legal entities created by the transaction with Yorktown is ignored.

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

        We acquired the Arkoma gathering system in September 2000 for a purchase price of approximately $10.5 million. The Arkoma system consisted of approximately 84 miles of gathering lines located in eastern Oklahoma. When acquired, the system was connected to approximately 115 wells, and purchased and resold approximately 12,000 MMBtu of gas per day.

22



        We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million. The Gulf Coast system consisted of approximately 484 miles of gathering and transmission lines extending from south Texas to markets near the Houston area. At the time of the acquisition, it was transporting approximately 117,000 MMBtu of gas per day.

        We acquired the CCNG system in May 2001 for a purchase price of approximately $30 million. The CCNG system included four principal assets: the Corpus Christi system, the Gregory gathering system, the Gregory processing plant and the Rosita treating plant.

        We acquired the Vanderbilt System in December 2002 for a purchase price of $12 million. The Vanderbilt System consists of approximately 200 miles of gathering lines in the same approximate geographic area as the Gulf Coast System. At the time of its acquisition it was transporting approximately 32,000 MMBtu of gas per day.

        Certain assets and liabilities of our predecessor were not contributed to our new partnership. These included receivables associated with the Enron Corp. bankruptcy discussed below under "—Results of Operations—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts," and any cost or benefit associated with the various puts and calls entered into to protect the value of our predecessor's position relative to the Enron matter. The Jonesville processing plant, which has been largely inactive since the beginning of 2001, and the recently acquired Clarkson plant were also not contributed.

Commodity Price Risks

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

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

        Changes in natural gas prices impact our profitability since the purchase price of a portion of the gas we buy (approximately 6.2% in 2002) is based on a percentage of a particular natural gas price index for a period, while the gas is resold at a fixed dollar relationship to the same index. Therefore, during periods of low gas prices, these contracts can be less profitable than during periods of higher

23



gas prices. However, on most of the gas we buy and sell, margins are not affected by such changes because the gas is bought and sold at a fixed relationship to the relevant index. Therefore, while changes in the price of gas can have very large impacts on revenues and cost of revenues, on this portion of the gas, the changes are equal and offsetting. For the twelve month period ending December 31, 2003, we currently have hedges in place for approximately 66% of the gas we anticipate we will purchase on a percentage of index price, at an average price of $3.528 per MMBtu (excluding price-sensitive gas associated with the recently acquired Vanderbilt system).

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

Results of Operations

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

 
  Year Ended December 31,
 
  2002
  2001
  2000
 
  (in millions)

Midstream revenues   $ 437.7   $ 362.7   $ 91.6
Midstream purchased gas     414.0     344.8     86.4
   
 
 
Midstream gross margin     23.7     17.9     5.2
   
 
 
Treating revenues     14.8     24.4     23.3
Treating purchased gas     5.8     18.1     19.6
   
 
 
Treating gross margin     9.0     6.3     3.7
   
 
 
Total gross margin   $ 32.7   $ 24.2   $ 8.9
   
 
 
Midstream Volumes (MMBtu/d):                  
  Gathering and transportation     392,608     313,103     77,527
  Processing     85,581     60,629     20,605
  Producer services     230,327     283,098     215,121
Treating Volumes (MMBtu/d)     97,033     62,782     32,938

        Revenues.    Midstream revenues were $437.7 million for the year ended December 31, 2002 compared to $362.7 million for the year ended December 31, 2001, an increase of $75.0 million, or 21%. Revenues were higher in 2002 than in 2001 due to the contribution of the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, which generated $120.5 million in additional revenues in 2002, as these assets were not acquired until May 2001. This increase was partially offset by a decline in natural gas prices from an average NYMEX settlement price of $4.273 per MMBtu in 2001 to $3.221 in 2002, which reduced revenues by $44.0 million.

        Treating revenues were $14.8 million for the year ended December 31, 2002 compared to $24.4 million in the same period in 2001, a decrease of $9.6 million, or 39%. The decline was due to the decrease in the price of natural gas, which accounted for $11.8 million of the decrease in treating revenues, a change in the contracts at certain plants to discontinue purchasing and reselling the treated gas and instead to receive only a treatment fee, which accounted for $4.8 million of the decrease, and a decrease in volume at one plant which accounted for $0.7 million of the decrease. This decline was partially offset by volume increases at two plants which generated an additional $5.6 million of revenue, 14 new plants placed in service in 2002 which collectively added $1.9 million, and the acquisition of the Rosita plant in May 2001, which generated an additional $0.3 million.

24



        Purchased Gas Costs.    Midstream purchased gas costs were $414.0 million for the year ended December 31, 2002 compared to $344.8 million for the year ended December 31, 2001, an increase of $69.2 million, or 20%. Costs increased by $113.7 million due to the Corpus Christi system, the Gregory gathering system and the Gregory processing plant. These facilities were purchased in May 2001 and only five months of their operating results are included in the 2001 period. This increase was partially offset by the decline in natural gas prices discussed above, which reduced costs by $44.0 million.

        Treating purchased gas costs were $5.8 million in 2002 compared to $18.1 million in 2001, a decrease of $12.3 million or 68%. The decrease in natural gas prices caused $7.2 million of the decline, certain contracts were restructured from a purchase and resale of the associated gas to a pure treatment fee, causing a decline of $4.8 million, and a decrease in treating volumes at one plant caused $0.7 million of the decline. This decrease was partially offset by costs at a new facility which created additional purchased gas costs of $.3 million.

        Operating Expenses.    Operating expenses were $10.5 million for the year ended December 31, 2002, compared to $7.4 million for the year ended December 31, 2001, an increase of $3.0 million, or 41%. The increase was primarily associated with the CCNG assets purchased in May 2001.

        General and Administrative Expenses.    General and administrative expenses were $8.5 million for the year ended December 31, 2002 compared to $5.9 million for the year ended December 31, 2001, an increase of $2.5 million, or 43%. The increases were associated with increases in staffing associated with the requirements of the CCNG assets and in preparation for our initial public offering.

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

        (Profit) Loss on Energy Trading Contracts.    The profit on energy trading contracts was $2.7 million for the year ended December 31, 2002 compared to a loss of $3.7 million for the year ended December 31, 2001, an increase of $6.4 million. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $1.8 million in 2002 and $1.9 million in 2001. In addition, gains of $0.9 million relating primarily to options bought and/or sold in the management of the company's Enron position were booked in 2002. Offsetting the gains from the producer services off-system gas marketing operations in 2001 was the $5.7 million reserve booked against the company's Enron receivable. See "Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts."

        Depreciation and Amortization.    Depreciation and amortization expenses were $7.7 million for the year ended December 31, 2002 compared to $6.1 million for the year ended December 31, 2001, an increase of $1.6 million, or 27%. The increase is primarily related to additional depreciation expense

25



associated with the CCNG assets purchased in May 2001, partially offset by a decrease in amortization expense due to goodwill no longer being amortized in 2002 in accordance with SFAS 142.

        Interest Expense.    Interest expense was $2.7 million for the year ended December 31, 2002 compared to $2.3 million for the year ended December31, 2001, an increase of $.4 million, or 21%. The increase relates primarily to bank debt incurred in the acquisitions of the CCNG assets in May, 2001, offset by lower interest rates.

        Net Income (Loss).    Net income (loss) for the year ended December 31, 2002 was $2.0 million compared to ($3.9) million for the year ended December 31, 2001, an increase of $5.9 million. Gross margin increased by $8.6 million from 2001 to 2002, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, and interest expense as discussed above. Non-cash charges for depreciation and amortization expenses and for impairment expense also increased, offset by the gain on energy trading activities.

        Revenues.    Midstream revenues were $362.7 million for the year ended December 31, 2001 compared to $91.6 million for the year ended December 31, 2000, an increase of $271.1 million, or 296%. Revenues were higher in 2001 primarily due to:

        The remaining increase in Midstream revenue is primarily attributable to the average price of natural gas in 2001 being approximately $0.39 per MMBtu higher than the average price in 2000.

        Revenues for natural gas treating were $24.4 million in 2001 compared to $23.3 million in 2000, an increase of $1.0 million, or 4%, due to new plants placed in service.

        Purchased Gas Costs.    Midstream division purchased gas costs for the year ended December 31, 2001 were $344.8 million compared to $86.4 million for the prior year, an increase of $258.3 million, or 299%. Costs were higher in 2001 primarily due to:

26


        Treating division purchased gas costs were $18.1 million in 2001 compared to $19.6 million in 2000, a decrease of $1.5 million, or 8%. In combination with the improvement in revenues in natural gas treating, the decrease in costs resulted in an improvement in gross margin of $2.5 million, or 68%. This improvement is primarily attributable to new plants placed in service for a fee, as opposed to purchase and resale of the gas.

        Operating Expenses.    Operating expenses were $7.4 million for the year ended December 31, 2001, compared to $2.3 million for the year ended December 31, 2000, an increase of $5.1 million, or 218%. Expenses were higher in 2001 than in 2000 primarily due to:

        General and Administrative Expenses.    General and administrative expenses were $5.9 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.1 million, or 110%. The increase in general and administrative expense is associated with the increase in employees caused by our rapid growth and preparation for our initial public offering. Total personnel employed increased from 44 to 107 between the end of 2000 and the end of 2001.

        Stock Based Compensation.    Stock based compensation expense was zero in 2001 compared to $8.8 million for the year ended December 31, 2000. The stock based compensation in 2000 is a charge associated with the valuation of management's interest in our predecessor as a result of the Yorktown investment in May 2000.

        Impairments.    Impairment expense was $2.9 million for the year ended December 31, 2001 compared to zero for the prior year. The impairment charge was recorded to reduce the carrying value of the Jonesville plant and related intangible assets to fair value in accordance with SFAS 121. See "—Critical Accounting Policies—Impairment of Long-Lived Assets" below.

        (Profit) Loss on Energy Trading Contracts.    The loss on energy trading contracts for the year ended December 31, 2001 was $3.7 million compared to a profit of $1.9 million for the prior year. The loss on energy trading contracts in 2001 includes $5.7 million associated with the write-down of the estimated realizable value of our receivable from Enron North America Corp., a subsidiary of Enron Corp., at December 31, 2001. On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp., each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Enron North America failed to make timely payment of approximately $3.9 million for physical delivery of gas in 2001. This amount remained outstanding as of December 31, 2001. Additionally, we had entered into natural gas hedging and physical delivery contracts with Enron North America. According to the terms of the contracts, Enron North America is liable to us for the

27



mark-to-market value of all contracts outstanding on the date we exercised our termination right under the contracts, which totaled approximately $4.6 million and which has been recorded as a receivable from Enron North America. We have accounted for these contracts as energy trading contracts whereby changes in fair value of the fixed price purchase commitments are recognized in earnings.

        We had offsets to the above amounts totaling approximately $0.3 million, resulting in a net $8.2 million receivable from Enron North America at December 31, 2001. Due to the uncertainty of future collections, a charge and related allowance for 70% of the net receivable, or $5.7 million, was recorded at December 31, 2001. Further adjustments to the Enron receivable will be recognized in earnings when management believes recovery of the asset is assured or additional reserves are warranted.

        The receivable from Enron was not contributed to our new partnership.

        Partially offsetting the Enron-related loss in the 2001 period are the realized margins on delivered volumes in the producer services "off-system" gas marketing operations. In 2001, the realized margins from the producer services operations were approximately $1.9 million, compared to approximately $1.8 million in 2000.

        Depreciation and Amortization.    Depreciation and amortization expense was $6.1 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.3 million, or 119%. The increase in depreciation and amortization is primarily related to acquisitions of new assets, which resulted in additional depreciation and amortization expense as follows:

        In addition, the accounting associated with the Yorktown investment in May 2000 resulted in an increase in depreciation and amortization for subsequent periods. Therefore, depreciation and amortization expense for the first four months of 2000 is approximately $0.4 million lower than if the investment had occurred at the beginning of 2000.

        Interest Expense.    Interest expense was $2.3 million for the year ended December 31, 2001 compared to $0.6 million for the year ended December 31, 2000, an increase of $1.6 million, or 270%. The increase was principally caused by increases in average outstanding borrowings as a result of the CCNG acquisition and the acquisition and refurbishment of treating plants. In addition, borrowings relative to the Arkoma and Gulf Coast assets were outstanding for the full year in 2001 as compared to only a part of 2000.

        Net Income (Loss).    Net loss for the year ended December 31, 2001 was ($3.9) million compared to ($6.1) million for the year ended December 31, 2000. Gross margin improved from $8.9 million in 2000 to $24.2 million in 2001, an improvement of $15.3 million, or 171%, largely as a result of acquisition-related growth as discussed above. This improvement was partially offset by increases in recurring cash charges for operating expenses, general and administrative expenses, and interest expense totaling $9.8 million, non-cash charges for depreciation and amortization of $3.3 million, and the loss on energy trading contracts and impairments totaling $8.5 million.

28



Critical Accounting Policies

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

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

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

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

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

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

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

29



physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

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

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

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

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

Liquidity and Capital Resources

        Cash Flows.    Net cash provided (used) in operating activities was $20.0 million, ($8.3) million, and $15.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash provided by operating activities in 2002 improved principally due to higher margins ($8.6 million) offset by higher cash expenses ($5.6 million), the loss on energy contracts related to Enron in 2001 ($5.7 million), and fund flows for working capital accounts. Net cash used in operating activities during the year ended December 31, 2001 was $23.4 million lower than the prior year principally attributable to higher margins ($15.3 million), offset by higher cash expenses ($9.8 million), the loss on energy trading contracts related to Enron ($5.7 million), and fund flows for working capital accounts.

        Net cash used in investing activities was $33.2 million, $52.5 million and $28.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash used in investing activities during all periods was primarily related to acquisition and internal growth projects. Net cash used in investing activities during each of the years ended December 31, 2002, 2001 and 2000 was primarily to fund

30



acquisitions of the Vanderbilt system, the CCNG assets, buying and refurbishing and installing treating plants, the Arkoma and Gulf Coast systems, the Millennium acquisition, and internal growth capital projects.

        Net cash provided by financing activities was $14.2 million, $42.6 million and $36.6 million for the years ended December 31, 2002, 2001 and 2000, respectively. Financing activities primarily represent equity investments and borrowings from banks to fund our acquisitions and other investments discussed above, and funding or refunding of the company's working capital needs.

        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. In addition, we are currently studying the possibility of expanding the capacity of our Gregory processing plant by 60,000 Mcf/d at an estimated cost ranging from $7.1 million to $9.2 million.

        We believe that cash generated from operations will be sufficient to meet our minimum quarterly distributions and anticipated maintenance capital expenditures through December 31, 2003. We expect to fund our growth capital expenditures from cash provided by operations and, to the extent necessary, from the proceeds of borrowings under the revolving credit facility discussed below and the issuance of additional common units. We may not be able to issue additional units or may not be able to issue such units on favorable terms primarily as a result of market conditions for our securities. Our ability to pay distributions to our unitholders 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.

        Total Contractual Cash Obligations.    A summary of our total contractual cash obligations as of December 31, 2002, is as follows:

 
  Payments due by period
Contractual Obligations

  Total
  Less than 1 year
  1-3 years
  3-5 years
  More than 5 years
 
  (in millions)

Long-Term Debt   $ 22.5       $ 11.0   $ 11.5  
Capital Lease Obligations                            
Operating Leases   $ 2.2   $ 0.8   $ 1.4      
Unconditional Purchase Obligations                            
Other Long-Term Obligations                            
Total Contractual Obligations   $ 24.7   $ 0.8   $ 12.4   $ 11.5  

31


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

Description of Credit Facility

        In connection with the closing of our initial public offering, we entered into a new $67.5 million credit facility, consisting of the following two facilities:

        The acquisition facility is used to finance the acquisition and development of gas gathering, treating and processing facilities, as well as general partnership purposes. At December 31, 2002, we had $21.8 million outstanding under the acquisition facility, leaving approximately $25.7 million available for future borrowings. The acquisition facility will convert into a term loan on April 30, 2004, and we will be required to make eleven quarterly payments equal to five percent of the outstanding borrowings. The first such payment will be due in July 2004. The term loan will mature in April 2007, at which time it will terminate and all outstanding amounts shall be due and payable. Prior to April 30, 2004, amounts borrowed and repaid under the acquisition credit facility may be reborrowed.

        The working capital facility is used for ongoing working capital needs, letters of credit, distributions and general partnership purposes, including future acquisitions and expansions. At December 31, 2002, we had $13.1 million of letters of credit issued under the working capital facility, leaving approximately $6.9 million available for future issuances of letters of credit, or up to $5.0 million of cash borrowings. The aggregate amount of borrowings under the working capital facility is subject to a borrowing base requirement relating to the amount of our cash and eligible receivables (as defined in the credit agreement), and there is a $5.0 million sublimit for cash borrowings. This facility will mature in April 2004, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital facility may be reborrowed. We are required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.

        Our obligations under the credit facility are secured by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of our equity interests in certain of our subsidiaries. The credit facility is guaranteed by certain of our subsidiaries. We may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs).

        Indebtedness under the acquisition facility and the working capital facility bear interest at our option at the administrative agent's reference rate plus 0.125% to 1.375% or LIBOR plus 1.625% to 2.875%. The applicable margin will vary quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.50% to 2.00% per annum, plus a fronting fee of 0.125% per annum. At December 31, 2002, our weighted average interest rate was 4.02%. We will incur quarterly commitment fees based on the unused amount of the credit facilities.

        In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement. The Partnership has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses

32



relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged.

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

        The credit facility also contains covenants requiring us to maintain:

        Each of the following is an event of default under the credit facility:

Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2000, 2001, or 2002. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

33



Environmental

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

Recent Accounting Pronouncements

        In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations, requiring business combinations entered into after June 30, 2001, to be accounted for using the purchase method of accounting. Specifically identifiable intangible assets acquired, other than goodwill, will be amortized over their estimated useful economic life. This pronouncement had no effect on our predecessor's financial position or results of operations.

        In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS No. 142 requires that we identify reporting units for purposes of assessing potential future impairments of goodwill, reassess the useful lives of other existing recognized intangible assets, and cease amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with the guidance in SFAS No. 142. This statement is required to be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS No. 142 required us to complete a transitional goodwill impairment test within six months from the date of adoption and reassess the useful lives of other intangible assets within the first interim quarter after adoption. Our predecessor had $4,873,000 recorded for goodwill, net of accumulated amortization at December 31, 2001 and recorded goodwill amortization expense of $292,000 for the year ended December 31, 2001. The only impact of adopting SFAS No. 142 on our financial statements was the discontinuance of the amortization of goodwill.

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

        In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 addresses financial accounting and reporting for impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to be Disposed Of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. This statement also amends ARB No. 51, Consolidated Financial Statements, to eliminate the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. See the impact of the adoption of SFAS No. 144 at Note 2 (c) of the Notes to Consolidated Financial Statements of our predecessor.

        In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than when the entity commits to an exit plan. This standard is effective for all exit or disposal activities which are initiated after December 31, 2002. We

34



do not anticipate that the adoption of SFAS No. 146 will have any impact on our financial position or results of operations.

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

        In June 2002, the Emerging Issues Task Force (EITF) reached consensus on certain issues in EITF Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts. Consensus was reached on two issues: 1) that gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the statement of operations, and 2) that entities should disclose the types of contracts that are accounted for as energy trading contracts along with a variety of other data regarding values, sensitivity to changes in estimates, maturity dates, and other factors. We early adopted this consensus in the second quarter of 2002 and all comparative financial statements were reclassified to report gains or losses on energy trading contracts net in the statements of operations. In October 2002, the EITF reached a consensus to rescind EITF 98-10. Accordingly, energy related contracts that are not accounted for pursuant to SFAS No. 133 should be accounted for as executory contracts and carried on an accrual basis, not fair value. The consensus should be applied prospectively to all new energy trading contracts entered into after October 25, 2002 and to all contracts that existed on October 25, 2002, in periods beginning after December 15, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principles. The rescission of EITF 98-10 did not have any significant effect on our financial position or results of operations.

        In January 2003, the FASB issued Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ending after December 15, 2002. The adoption of the statement is not expected to have a material effect on the Partnership's financial statements when adopted.

        In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities. FIN No. 46 requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after June 15, 2003. The Partnership is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN No. 46 will not have an impact on our financial statements.

35



Risk Factors

        Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.

        Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. We cannot guarantee that we will be able to pay the minimum quarterly distributions of $0.50 per common unit in each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

        Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

        From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        The success of our business strategy to increase and optimize throughput on our pipeline and gathering assets is dependent upon our securing additional supplies of natural gas.

        Our operating results are dependent upon securing additional supplies of natural gas from increased production by natural gas production companies in the Texas Gulf Coast. The ability of producers to increase production is dependent on natural gas prices, the exploration and production budgets of the production companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters beyond our control. There can be no assurance that production of natural gas will rise to sufficient levels to maintain or increase the throughput on our pipeline and gathering assets.

        Our operations are dependent upon demand for natural gas by industry and utilities in the Texas Gulf Coast. Any decrease in this demand could adversely affect our business.

        We face intense competition in our gathering and marketing activities. Our competitors include other natural gas pipelines and their marketing affiliates, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of natural gas. See Item 1. "Business—Competition."

        We are exposed to the credit risk of our customers in the ordinary course of our gathering and marketing activities. In our gathering and marketing operations, we take title to the natural gas and resell the gas to our various market outlets, which include a variety of utility, refining, petrochemical, metals production and other industrial consumers, as well as to the pipeline companies. A significant failure to pay by one of our major customers would adversely affect our ability to maintain distributions.

        In conjunction with the Yorktown investment in July, 2000, we allocated $14.2 million in value to intangible assets and $4.6 million to goodwill. At December 31, 2002, $5.3 million and $4.9 million of intangible assets and goodwill, respectively, remain as assets in the consolidated balance sheets. We

36



evaluate these assets for impairment at least annually. Changes in the Company's business could result in impairments of these assets.

Disclosure Regarding Forward-Looking Statements

        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), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "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.

        These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number or risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

        Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Risk Factors," and elsewhere in this report.

        You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. You should be aware that the occurrence of any of the events described in "Risk Factors" and elsewhere in this prospectus could substantially harm our business, results of operations and financial condition and that, upon the occurrence of any of these events, the trading price of our common units could decline.

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


Item 7A. 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 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 6.2% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 44% of the gas we purchased during the year ended December 31, 2002. Our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the year ended December 31, 2002, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have changed our processing margin by $446,738. Changes in natural gas prices indirectly may impact our profitability since prices

37



can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.

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

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

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

        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 December 31, 2002, we had $21.8 million of indebtedness outstanding. We have interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein we have swapped floating rates for fixed rates of 2.29% and the applicable margin for a period of two years. The impact of a 100 basis point increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $218,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our debt outstanding at December 31, 2002.


Item 8. Financial Statements and Supplementary Data

        The Report of Independent Public Accountants, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-35 and S-1 of this Report and are incorporated herein by reference.

38



Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

        None.


PART III

Item 10. Directors and Executive Officers of the Registrant

        As is the case with many publicly traded partnerships, we do not have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Crosstex Energy GP, LLC. Our operational personnel are employees of the Operating Partnership. References to our general partner, unless the context otherwise requires, includes Crosstex Energy GP, LLC. References to our officers, directors and employees are references to the officers, directors and employees of Crosstex Energy GP, LLC.

        Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders, as limited by our partnership agreement. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.

        Three members of the board of directors of our general partner, namely Messrs. Haden, Murchison and Wells, serve on a conflicts committee, which reviews specific matters that the board believes may involve conflicts of interest between our general partner and Crosstex Energy, L.P. The conflicts committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee are not officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders.

        The Audit Committee of our general partner, comprised of Messrs. Wells and Haden, provides oversight for the external financial reporting of the Partnership. The Compensation Committee of our general partner, comprised of Messrs. Lubar and Murchison, oversees compensation decisions for the officers of the General Partner as well as the compensation plans described below.

        The following table shows information for the directors and executive officers of Crosstex Energy GP, LLC. Executive officers and directors are elected annually and have held the following positions since the date of the closing of our initial public offering, except for Messrs. Davis and Lawrence who have held the following positions with the Crosstex Energy GP, LLC since its formation in July 2002.

Name

  Age
  Position with Crosstex Energy GP, LLC
Barry E. Davis   41   President, Chief Executive Officer and Director
James R. Wales   49   Executive Vice President—Midstream Division
A. Chris Aulds   41   Executive Vice President—Treating Division
Jack M. Lafield   52   Senior Vice President—Business Development
William W. Davis   49   Senior Vice President and Chief Financial Officer
Michael P. Scott   48   Senior Vice President—Engineering and Operations
C. Roland Haden   62   Director and Member of the Audit and Conflicts Committees
Bryan H. Lawrence   60   Chairman of the Board and Director
Sheldon B. Lubar   73   Director and Member of the Compensation Committee*
Robert F. Murchison   48   Director and Member of the Compensation and Conflicts Committees
Stephen A. Wells   59   Director and Member of the Audit* and Conflicts Committees

*
Indicates chairman of committee.

        Barry E. Davis, President, Chief Executive Officer and Director, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of our predecessor. Mr. Davis was President and Chief Operating Officer of Comstock

39



Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis holds a B.B.A. in Finance from Texas Christian University.

        James R. Wales, Executive Vice President—Midstream Division, joined our predecessor in December 1996. As one of the founders of Sunrise Energy Services, Inc., he helped build Sunrise into a major national independent natural gas marketing company, with sales and service volumes in excess of 600,000 MMBtu/d. Mr. Wales started his career as an engineer with Union Carbide. In 1981, he joined Producers Gas Company, a subsidiary of Lear Petroleum Corp., and served as manager of its Mid-Continent office. In 1986, he joined Sunrise as Executive Vice President of Supply, Marketing and Transportation. From 1993 to 1994, Mr. Wales was the Chief Operating Officer of Triumph Natural Gas, Inc., a private midstream business. Prior to joining Crosstex, Mr. Wales was Vice President for Teco Gas Marketing Company. Mr. Wales holds a B.S. degree in Civil Engineering from the University of Michigan, and a Law degree from South Texas College of Law.

        A. Chris Aulds, Executive Vice President—Treating Division, together with Barry E. Davis, participated in the management buyout of Comstock Natural Gas in December 1996. Mr. Aulds joined Comstock Natural Gas, Inc. in October 1994 as a result of the acquisition by Comstock of the assets and operations of Victoria Gas Corporation. Mr. Aulds joined Victoria in 1990 as Vice President responsible for gas supply, marketing and new business development and was directly involved in the providing of risk management services to gas producers. Prior to joining Victoria, Mr. Aulds was employed by Mobil Oil Corporation as a production engineer before being transferred to Mobil's gas marketing division in 1989. There he assisted in the creation and implementation of Mobil's third- party gas supply business segment. Mr. Aulds holds a B.S. degree in Petroleum Engineering from Texas Tech University.

        Jack M. Lafield, Senior Vice President—Business Development, joined our predecessor in August 2000. For five years prior to joining Crosstex, Mr. Lafield was Managing Director of Avia Energy, an energy consulting group, and was involved in all phases of acquiring, building, owning and operating midstream assets and natural gas reserves. He also provided project development and consulting in domestic and international energy projects to major industry and financing organizations, including development, engineering, financing, implementation and operations. Prior to consulting, Mr. Lafield held positions of President and Chief Executive Officer of Triumph Natural Gas, a private midstream business he founded, President and Chief Operating Officer of Nagasco, Inc. (a joint venture with Apache Corporation), President of Producers' Gas Company, and Senior Vice President of Lear Petroleum Corp. Mr. Lafield holds a B.S. degree in Chemical Engineering from Texas A&M University, and is a graduate of the Executive Program at Stanford University.

        William W. Davis, Senior Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has 25 years of finance and accounting experience. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President—Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant. Mr. Davis is not related to Barry E. Davis.

        Michael P. Scott, Senior Vice President—Engineering and Operations, joined our predecessor in July 2001. Before joining our predecessor, Mr. Scott held various positions at Aquila Gas Pipeline Corporation, including Director of Engineering from 1992 to 2001, Director of Operations from 1990 to 1992, and Director of Project Development from 1989 to 1990. Prior to Aquila, Mr. Scott held various project development and engineering positions at Cabot Corporation/Cabot Transmission, Perry

40



Gas Processors and General Electric. Mr. Scott holds a B.S. degree in Mechanical Engineering from Oklahoma State University.

        C. Roland Haden joined us as a director upon the completion of our initial public offering. Mr. Haden held the positions of Vice Chancellor of the Texas A&M System, Director of the Texas Engineering Experiment Station and Dean of Look College of Engineering at Texas A&M University from 1993 to 2002. Prior to joining Texas A&M University, Mr. Haden served as Vice Chancellor for Academic Affairs and Provost of Louisiana State University from 1991 to 1993 and held various positions with Arizona State University, including Dean and Professor of Engineering & Applied Sciences from 1989 to 1991, Provost, ASU West Campus from 1988 to 1989, Vice President for Academic Affairs from 1987 to 1988 and Dean and Professor of Engineering and Applied Sciences from 1978 to 1987. Mr. Haden formerly served as a director of Square D Company, a Fortune 500 electrical manufacturing company, as a director of E-Systems, a Fortune 500 defense contractor, and as a member of the Telecommunications Advisory Board of A.T. Kearney, a nationally ranked consulting firm. He has been a director of Inter-tel, Inc., a leading telecommunications company, since 1983. Mr. Haden holds a bachelor's degree from the University of Texas, Arlington, a Masters degree from the California Institute of Technology, and a Ph.D. from the University of Texas, Austin, all in electrical engineering.

        Bryan H. Lawrence, Chairman of the Board, joined our predecessor as a director in May 2000. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Carbon Energy Corporation, D&K Healthcare Resources, Inc., Hallador Petroleum Company, TransMontaigne Inc., and Vintage Petroleum, Inc. (each a United States publicly traded company) and Cavell Energy Corp. (a Canadian publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor Resources Inc., Camden Resources, Inc., ESI Energy Services Inc., Ellora Energy Inc., and Dernick Resources Inc. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.

        Sheldon B. Lubar joined us as a director upon the completion of our initial public offering. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar has also been a Director of C2, Inc., a logistics and manufacturing company, since 1995, MGIC Investment Corporation, a mortgage insurance company, since 1991, Grant Prideco, Inc., an energy services company, since 2000, and Weatherford International, Inc., an energy services company, since 1995. Mr. Lubar holds a bachelor's degree in Business Administration and a Law degree from the University of Wisconsin—Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin—Milwaukee.

        Robert F. Murchison joined us as a director upon the completion of our initial public offering. Mr. Murchison has been the President of the general partner of Murchison Capital Partners, L.P., a private equity investment partnership since 1992. Prior to founding Murchison Capital Partners, L.P., Mr. Murchison held various positions with Romacorp, Inc., the franchisor and operator of Tony Roma's restaurants, including Chief Executive Officer from 1984 to 1986 and Chairman of the board of directors from 1984 to 1993. He served as a director of Cenergy Corporation, an oil and gas exploration and production company, from 1984 to 1987, Conquest Exploration Company from 1987 to 1991 and has served as a director of TNW Corporation, a short line railroad holding company, since 1981 and Tecon Corporation, a holding company with holdings in real estate development, investor

41



owned water utilities, rail car repair and the fund of funds management business, since 1978. Mr. Murchison holds a bachelor's degree in history from Yale University.

        Stephen A. Wells joined us as a director upon the completion of our initial public offering. Mr. Wells has been the President of Wells Resources, Inc., a private oil, gas and ranching company since 1983. Mr. Wells has served in executive management positions with various energy companies, with an emphasis in oil field services. He served as Chief Executive Officer and director of Grasso Corporation, a contract production management company, from 1992 to 1994, Chief Executive Officer and director of Coastwide Energy Services, Inc. from 1993 to 1996, and President, Chief Executive Officer and director of Wells Strathclyde Company, an oil field services company he co-founded from 1978 to 1982. Mr. Wells also serves as a director and audit committee chair of Oil States International and as a director and audit committee chair of Pogo Producing Company. Mr. Wells holds a bachelor's degree in accounting from Abilene Christian University.

Section 16(a)—Beneficial Ownership Reporting Compliance

        Section 16(a) of the Securities Exchange Act of 1934 requires the directors and certain officers of the General Partner and any 10% beneficial owners of the Partnership to send reports of their beneficial ownership of Common Units and changes in beneficial ownership to the Securities and Exchange Commission. Based on our records, we believe that during Fiscal 2002 all of such reporting persons complied with all Section 16(a) filing requirements applicable to them.

Reimbursement of Expenses of our General Partner and its Affiliates

        Our general partner does not receive any management fee or other compensation in connection with its management of Crosstex Energy, L.P. However, our general partner performs services for us and is reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the first 12 months following our initial public offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on behalf of the partnership. See Item 13. "Certain Relationships and Related Transactions."


Item 11. Executive Compensation

        The following table sets forth certain compensation information for our Chief Executive Officer and the five other most highly compensated executive officers in 2002. We reimburse our general partner and its affiliates for expenses incurred on our behalf, including the costs of officer compensation allocable to us. The named executive officers have also received certain equity-based awards from our general partner's general partner. The Partnership was formed in July 2002 but conducted no business until mid-December 2002. As such, the compensation set forth below includes salary and bonus information paid to each of the named executive officers by the Partnership and its predecessor.

42



Summary Compensation Table

 
   
   
   
   
  Long Term
Compensation Awards

 
   
  Annual Compensation (1)
 
   
  Units
Underlying
Options
(#)(3)

   
Name and
Principal Position

  Year
  Salary (1)
($)

  Bonus (2)
($)

  Other Annual
Compensation
($)

  All Other
Compensation
($)

Barry E. Davis
President and Chief Executive Officer
  2002   201,500   100,750     30,000  
James R. Wales
Executive Vice President—Midstream Division
  2002   171,064   59,872     20,000  
A. Chris Aulds
Executive Vice President—Treating Division
  2002   171,064   59,872     20,000  
Jack M. Lafield
Senior Vice President—Business Development
  2002   160,875   56,306     17,500  
William W. Davis
Senior Vice President and Chief Financial Officer
  2002   160,875   96,306     17,500  
Michael P. Scott
Senior Vice President—Engineering and Operations
  2002   134,304   47,007     12,500  

(1)
Reflects the aggregate salary paid by the registrant and its predecessor for fiscal 2002. The portion of the amount shown paid by the registrant subsequent to the closing of its initial public offering on December 17, 2002 for each of Messrs. Davis, Wales, Aulds, Lafield, W. Davis, and Scott was $8,396, $7,128, $7,128, $6,703, $6,703 and $5,596, respectively.
(2)
Performance bonuses were earned by the executive officers for service to the registrant's predecessor prior to the closing of its initial public offering.
(3)
Executive officers have received equity-based awards from our general partner. No awards have vested to date under our Long-Term Incentive Plan. For a description of awards granted to date under the Long-Term Incentive Plan. See "—Long-Term Incentive Plan."

Employment Agreements

        The executive officers of the general partner of our general partner, including Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, have entered into employment agreements with Crosstex Energy, L.P. The following is a summary of the material provisions of those employment agreements. All of these employment agreements are substantially similar, with certain exceptions as set forth below.

        Each of the employment agreements has an initial term that expires two years from the effective date, but will automatically be extended such that the remaining term of the agreements will not be less than one year. The employment agreements provide for a base annual salary of $201,500, $171,064, $171,064, $160,875, $160,875 and $134,304 for Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, respectively.

        Except in the event of our becoming bankrupt or ceasing operations, termination for cause or termination by the employee other than for good reason, the employment agreements provide for continued salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement. If a change in control occurs during the term of an employee's employment and either party to the agreement terminates the employee's employment as a result thereof, the employee will be entitled to receive salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement.

43



        The employment agreements also provide for a noncompetition period that will continue until the later of one year after the termination of the employee's employment or the date on which the employee is no longer entitled to receive severance payments under the employment agreement. During the noncompetition period, the employees are generally prohibited from engaging in any business that competes with us or our affiliates in areas in which we conduct business as of the date of termination and from soliciting or inducing any of our employees to terminate their employment with us or accept employment with anyone else or interfere in a similar manner with our business.

Long-Term Incentive Plan

        Crosstex Energy GP, LLC adopted a long-term incentive plan for employees and directors of Crosstex Energy GP, LLC and its affiliates who perform services for us.

        The long-term incentive plan consists of two components: restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 700,000 common units, 233,000 of which may be awarded in the form of restricted units and 467,000 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of Crosstex Energy GP, LLC's board of directors.

        Crosstex Energy GP, LLC's board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Crosstex Energy GP, LLC's board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

        Restricted Units.    A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. In the future, the compensation committee may make grants under the plan to employees and directors containing such terms as the compensation committee shall determine under the plan. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us, our general partner or Crosstex Energy GP, LLC.

        If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by Crosstex Energy GP, LLC in the open market, common units already owned by Crosstex Energy GP, LLC, common units acquired by Crosstex Energy GP, LLC directly from us or any other person or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units.

        We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

        Unit Options.    The long-term incentive plan currently permits the grant of options covering common units. Unit options will have an exercise price that, in the discretion of the compensation committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the

44



compensation committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner or Crosstex Energy GP, LLC or upon the achievement of specified financial objectives.

        Upon exercise of a unit option, Crosstex Energy GP, LLC will acquire common units in the open market or directly from us or any other person or use common units already owned by Crosstex Energy GP, LLC, or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Crosstex Energy GP, LLC will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

Option Grants

        The following table contains information about unit option grants to the named executive officers in 2002 (except as indicated):

Option Grants in Last Fiscal Year

 
  Individual Grants
   
   
 
   
 
   
   
   
   
 
   
   
   
  Potential realizable
value at assumed annual rates of unit price appreciation for option term

 
   
   
  Exercise or base price ($/Unit)
   
   
Name

  Number of securities underlying Options
granted (#)

  Percent of total options
granted to employees in fiscal year (1)

  Market Price on Date of Grant ($/Unit)
  Expiration date
  5% ($)
  10% ($)
Barry E. Davis   30,000   15.4%   20.00   20.00   12/17/12   377,337   956,245
James R. Wales   20,000   10.3%   20.00   20.00   12/17/12   251,558   637,497
A. Chris Aulds   20,000   10.3%   20.00   20.00   12/17/12   251,558   637,497
Jack M. Lafield   17,500   9.0%   20.00   20.00   12/17/12   220,113   557,810
William W. Davis   17,500   9.0%   20.00   20.00   12/17/12   220,113   557,810
Michael P. Scott   12,500   6.4%   20.00   20.00   12/17/12   157,224   398,436

(1)
The total number of options granted to employees in 2002 used to calculate these percentages includes 195,000 common units underlying options granted upon the closing of the Company's initial public offering. The options vest at a rate of 1/3 per year beginning December 17, 2003.
(2)
All options granted were under the Crosstex Energy, LLC Long-Term Incentive Plan

Option Exercises and Year-End Option Values

        The following table provides information about the number of units issued upon option exercises by the named executive officers during 2002, and the value realized by the named executive officers. The table also provides information about the number and value of options that were held by the named executive officers at December 31, 2002.

45



Aggregated Option Exercise in Last Fiscal Year
and Fiscal Year End Option Values

 
   
   
  Number of Securities Underlying Unexercised Options at 12/31/02 (#)
  Value of Unexercised
In-the-Money Options at 12/31/02 ($)

Name

  Shares Acquired on
Exercise (#)

  Value
Realized ($)

  Exercisable
  Unexercisable
  Exercisable
  Unexercisable
Barry E. Davis   0   0   0   30,000   0   $ 42,000
James R. Wales   0   0   0   20,000   0     28,000
A. Chris Aulds   0   0   0   20,000   0     28,000
Jack M. Lafield   0   0   0   17,500   0     24,500
William W. Davis   0   0   0   17,500   0     24,500
Michael P. Scott   0   0   0   12,500   0     17,500

Compensation of Directors

        Each director of Crosstex Energy GP, LLC who is not an employee of Crosstex Energy GP, LLC (except Mr. Lawrence) is paid an annual retainer fee of $25,000. Directors do not receive an attendance fee for each board meeting, but an attendance fee of $1,000 is paid to each director for each committee meeting he attends. Directors are also reimbursed for related out-of-pocket expenses. Each committee chairman receives $2,500 annually. Barry E. Davis, as an officer of Crosstex Energy GP, LLC, is otherwise compensated for his services and therefore receives no separate compensation for his service as a director. Directors are also entitled to a one-time grant of 10,000 options at an exercise price of $20.

Compensation Committee Interlocks And Insider Participation

        The Compensation Committee of the board of directors of Crosstex Energy GP, LLC determines compensation of the executive officers. Sheldon B. Lubar and Robert F. Murchison served as members of the Compensation Committee of the board of directors of Crosstex Energy GP, LLC upon the completion of our initial public offering.

46



Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The following table shows the beneficial ownership of units of Crosstex Energy, L.P. as of March 4, 2003 held by:


Name of Beneficial Owner (1)

  Common Units Beneficially Owned
  Percentage of Common Units Beneficially Owned
  Subordinated Units Beneficially Owned
  Percentage of Subordinated Units Beneficially Owned
  Percentage of Total Units Beneficially Owned
 
Crosstex Energy Holdings Inc.   333,000   12.7 % 4,667,000   100.0 % 68.5 %
Barry E. Davis(2)(3)            
James R. Wales(2)(3)            
A. Chris Aulds(2)(3)            
Jack M. Lafield(2)(3)            
William W. Davis(2)(3)            
Michael P. Scott(2)(3)            
C. Roland Haden(4)   2,500          
Bryan H. Lawrence(5)            
Sheldon B. Lubar(6)            
Stephen A. Wells   5,000          
Robert F. Murchison(7)   25,000          
All directors and executive officers as a group (11 persons)   32,500   1.2 %     *  

*
Less than 1%.
(1)
The address of each person listed above is 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, except for Crosstex Energy Holdings Inc. and Bryan H. Lawrence which is 410 Park Avenue, New York, New York 10022.
(2)
Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott each hold an ownership interest in Crosstex Energy Holdings Inc. as indicated in the following table.
(3)
Grants of options to purchase a total of 195,000 common units were made upon the closing of the initial public offering to employees of Crosstex Energy GP, LLC, including the named executive officers. See "—Long-Term Incentive Plan."
(4)
These units are held in a trust for the benefit of the Mr. Haden's children. Mr. Haden and his spouse are trustees of the trust.
(5)
Bryan H. Lawrence is a member and a manager of the general partner of both Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. Both of these limited partnerships own an interest in Crosstex Energy Holdings Inc. as indicated in the following table.
(6)
Sheldon B. Lubar is a general partner of Lubar Nominees, and Lubar Nominees holds an ownership interest in Crosstex Energy Holdings Inc. as indicated in the following table.
(7)
These units are held by Murchison Capital Partners, L.P. Mr. Murchison is the President of the Murchison Management Corp., which serves as the general partner of Murchison Capital Partners, L.P.

47


        The following table shows the beneficial ownership of Crosstex Energy Holdings Inc. as of March 4, 2003. Crosstex Energy Holdings Inc. owns Crosstex Energy GP, LLC and, together with Crosstex Energy GP, LLC, our general partner and, as reflected above, common units and subordinated units.

Name of Beneficial Owner(1)

  Percent
of Equity

 
Yorktown Energy Partners IV, L.P.(2)   61.6 %
Yorktown Energy Partners V, L.P.(2)   15.4 %
Lubar Nominees(3)   6.0 %
Barry E. Davis(4)   7.14 %
James R. Wales(4)   3.36 %
A. Chris Aulds(4)   4.57 %
Jack M. Lafield(4)   *  
William W. Davis(4)   *  
Michael P. Scott(4)   *  
C. Roland Haden    
Bryan H. Lawrence(5)    
Sheldon B. Lubar(3)   6.0 %
Stephen A. Wells    
Robert F. Murchison    
All directors and executive officers as a group (11 persons)(4)   22.89 %

*
Less than 1%.
(1)
Unless otherwise indicated, the address of each person listed above is 2501 Cedar Springs, Suite 600, Dallas, Texas 75201.
(2)
The address for Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. is 410 Park Avenue, New York, New York 10022.
(3)
Sheldon B. Lubar is a general partner of Lubar Nominees, and may be deemed to beneficially own the shares held by Lubar Nominees.
(4)
Ownership percentage for such individual or group includes shares issuable pursuant to stock options which are presently exercisable or exercisable within 60 days.
(5)
Bryan H. Lawrence is a member and a manager of the general partner of both Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P.

Beneficial Ownership of General Partner Interest

        Crosstex Energy GP, L.P. owns all of our 2% general partner interest and all of our incentive distribution rights. Crosstex Energy GP, L.P. is owned 0.001% by its general partner, Crosstex Energy GP, LLC and 99.999%; by its sole limited partner, Crosstex Energy Holdings Inc.

48


Equity Compensation Plan Information

Plan Category

  Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, And Rights (a)
  Weighted-Average Price Of Outstanding Options, Warrants And Rights (b)
  Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected In Column (a)) (c)
 
Equity Compensation Plans Approved By Security Holders   N/A     N/A   N/A  
Equity Compensation Plans Not Approved By Security Holders   700,000 (1) $ 20.00 (2) 505,000 (3)

(1)
Our general partner has adopted and maintains a Long Term Incentive Plan for our officers, employees and directors. See Item 11. "Executive Compensation—Long-Term Incentive Plan." The LTIP contemplates awards of up to 233,000 restricted units and 467,000 unit options.
(2)
The current strike price for all outstanding options under the plan is $20.00 per unit.
(3)
Consisting of 233,000 restricted units and 272,000 unit options.


Item 13. Certain Relationships and Related Transactions

Our General Partner

        Our operations and activities are managed by, and our officers are employed by, the operating partnership. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf. For the first 12 months following our initial public offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on behalf of the partnership.

        Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.450 per unit, 23% of the amounts we distribute in excess of $0.50 per unit and 48% of amounts we distribute in excess of $0.675 per unit.

Relationship with Crosstex Energy Holdings Inc.

        General.    Crosstex Energy Holdings Inc. owns 333,000 common units and 4,667,000 subordinated units representing an aggregate 68.5% limited partnership interest in us. Our general partner owns a 2% general partner interest in us and the incentive distribution rights. Our general partner's ability, as general partner, to manage and operate Crosstex Energy, L.P. and Crosstex Energy Holdings' ownership of an aggregate 68.5% limited partner interest in us effectively gives our general partner the ability to veto some of our actions and to control our management.

        Omnibus Agreement.    Concurrent with the closing of our initial public offering, we entered into an agreement with Crosstex Energy Holdings Inc., Crosstex Energy GP, LLC and our general partner which will govern potential competition among us and the other parties to the agreement. Crosstex Energy Holdings Inc. agreed, and caused its controlled affiliates to agree, for so long as management, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. and its affiliates, or any

49



combination thereof, control our general partner, not to engage in the business of gathering, transmitting, treating, processing, storing and marketing of natural gas and the transportation, fractionation, storing and marketing of NGLs unless it first offers us the opportunity to engage in this activity or acquire this business, and the board of directors of Crosstex Energy GP, LLC, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. In addition, Crosstex Energy Holdings Inc. has the ability to purchase a business that has a competing natural gas gathering, transmitting, treating, processing and producer services business if the competing business does not represent the majority in value of the business to be acquired and Crosstex Energy Holdings Inc. offers us the opportunity to purchase the competing operations following their acquisition. The noncompetition restrictions in the omnibus agreement do not apply to the assets retained and business conducted by Crosstex Energy Holdings Inc. at the closing of our initial public offering. Except as provided above, Crosstex Energy Holdings Inc. and its controlled affiliates are not prohibited from engaging in activities in which they compete directly with us. In addition, Yorktown Energy Partners IV, L.P., Yorktown Energy Partners V, L.P. and any affiliated Yorktown funds are not prohibited from owning or engaging in businesses which compete with us.

Initial Public Offering and Concurrent Transactions

        On December 17, 2002, the Partnership completed an initial public offering of 2,300,000 common units representing limited partner interests and received therefrom net proceeds of approximately $40.2 million. Concurrently with the closing of the initial public offering, certain transactions were consummated in connection with the formation of the Partnership. These transactions involved the transfer to us by Crosstex Energy Holdings Inc. of substantially all the assets and liabilities of Crosstex Energy Services, Ltd. (the predecessor of our operating partnership Crosstex Energy Services, L.P.) in exchange for and the right to receive $2.5 million from the proceeds of the initial public offering and the issuance of 333,000 common units and 4,667,000 subordinated units (which are held by Crosstex Energy Holdings Inc.) and the incentive distribution rights and a 2% general partner interest in the Partnership (which are held by Crosstex Energy GP, L.P.). In addition, certain assets and liabilities of Crosstex Energy Services, Ltd. were not contributed to the Partnership, but, instead, were transferred to a subsidiary of Crosstex Energy Holdings Inc. These include receivables associated with the Enron Corp. bankruptcy discussed above under "Item 7. Management's Discussion and Analysis of Financial Position and Results of Operations—Results of Operations—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts." Also, the Jonesville processing plant, which was largely inactive since the beginning of 2001, and the recently acquired Clarkson plant were not contributed to the Partnership, but, instead were transferred to a subsidiary of Crosstex Energy Holdings Inc.

Related Party Transactions

        Camden Resources, Inc.    We treat gas for, and purchase gas from, Camden Resources, Inc. Yorktown Energy Partners IV, L.P. has made equity investments in both Camden and Crosstex Energy Holdings Inc. The gas treating and gas purchase agreements we have entered into with Camden are standard industry agreements containing terms substantially similar to those contained in our agreements with other third parties. During the year ended December 31, 2002, we purchased natural gas from Camden Resources, Inc. in the amount of approximately $10.1 million and received approximately $399,000 in treating fees from Camden Resources, Inc.

        Crosstex Pipeline Company.    We indirectly own general and limited partner interests in Crosstex Pipeline Partners, L.P. that represent a 28% economic interest. We have entered into various transactions with Crosstex Pipeline Partners, and we believe that the terms of these transactions are comparable to those that we could have negotiated with unrelated third parties. During the year ended December 31, 2002, our predecessor: (1) purchased natural gas from Crosstex Pipeline Partners in the amount of approximately $3.4 million and paid Crosstex Pipeline Partners approximately $27,000 for transportation of natural gas, (2) received a management fee from Crosstex Pipeline Partners in the

50



amount of approximately $125,000 and (3) received approximately $90,000 in distributions from Crosstex Pipeline Partners;


Item 14. Controls And Procedures

        An evaluation of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures as of March 21, 2003 was carried out by the General Partner under the supervision and with the participation of the General Partner's management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures have been designed and are being operated in a manner that provides reasonable assurance that the information required to be disclosed by the Partnership in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. A controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within an entity have been detected. Subsequent to the date of the most recent evaluation of the Partnership's internal controls, there were no significant changes in the Partnership's internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

51



PART IV


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

        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):

Number

   
  Description
3.1     Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Registration Statement, file No. 333-97779).

3.2

*


 

Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of December 17, 2002

3.3

 


 

Certificate of Limited Partnership of Crosstex Energy Services, Ltd. (incorporated by reference to Exhibit 3.3 to Registration Statement, file No. 333-97779).

3.4

*


 

Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, Ltd., dated as of December 17, 2002

3.5

 


 

Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Registration Statement, file No. 333-97779).

3.6

 


 

Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to Registration Statement, file No. 333-97779).

3.7

 


 

Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Registration Statement, file No. 333-97779).

3.8

*


 

Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of July 10, 2002

4.1

 


 

Specimen Unit Certificate for Common Units (incorporated by reference to Exhibit 4.1 to Registration Statement, file No. 333-97779).

10.1

*


 

Second Amended and Restated Credit Agreement, dated November 26, 2002, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and Fleet National Bank

10.2

*


 

First Contribution, Conveyance and Assumption Agreement, dated November 27, 2002, among Crosstex Energy, L.P. and certain other parties

10.3

*


 

Closing Contribution, Conveyance and Assumption Agreement, dated December 11, 2002, among Crosstex Energy, L.P. and certain other parties

10.4*

+


 

Crosstex Energy GP, LLC Long-Term Incentive Plan, dated July 12, 2002

10.5

*


 

Omnibus Agreement, dated December 17, 2002, among Crosstex Energy, L.P. and certain other parties

10.6

*


 

Form of Employment Agreement

10.7

 


 

Gas Sales Agreement, dated March 1, 2001 among Tejas Gas Marketing, LLC, Corpus Christi Gas Marketing, L.P. and Corpus Christi Gas Processing, L.P., as amended by the Amendment to Gas Sales Agreement, dated October 1, 2001, among Tejas Gas Marketing, LLC and Crosstex CCNG Marketing, L.P. (incorporated by reference to Exhibit 10.6 to Registration Statement, file No. 333-97779).

10.8

 


 

Gas Sales Agreement, dated December 17, 1998, among Reliant Energy Entex and GC Marketing Company, as amended by the Amendment to Gas Sales Agreement, dated June 18, 2002, among Crosstex Gulf Coast Marketing, Ltd. and Reliant Energy Entex (incorporated by reference to Exhibit 10.7 to Registration Statement, file No. 333-97779).

21.1

*


 

List of Subsidiaries

99.1

*


 

CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act

99.2

*


 

CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act

*
Filed herewith.

+
As required by Item 14(a)(3), this exhibit is identified as a compensatory benefit plan or arrangement

(b)
Reports on Form 8-K.

        None.

52



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 21st day of March 2003.

    CROSSTEX ENERGY, L.P.

 

 

By:

 

Crosstex Energy GP, L.P.,
its general partner

 

 

 

 

By:  Crosstex Energy GP, LLC,
        its general partner

 

 

 

 

        By:  /s/  
BARRY E. DAVIS    
                

                Barry E. Davis,
                President and Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities with Crosstex Energy GP, LLC, general partner of Crosstex Energy GP, L.P., general partner of the Registrant, indicated.

Signature

  Title
  Date

 

 

 

 

 
/s/  BARRY E. DAVIS      
Barry E. Davis
  President, Chief Executive Officer and Director (Principal Executive Officer)   March 21, 2003

/s/  
C. ROLAND HADEN      
C. Roland Haden

 

Director

 

March 24, 2003

/s/  
BRYAN H. LAWRENCE      
Bryan H. Lawrence

 

Chairman of the Board and Director

 

March 24, 2003

/s/  
SHELDON B. LUBAR      
Sheldon B. Lubar

 

Director

 

March 24, 2003

/s/  
ROBERT F. MURCHISON      
Robert F. Murchison

 

Director

 

March 24, 2003

/s/  
STEPHEN A. WELLS      
Stephen A. Wells

 

Director

 

March 22, 2003

/s/  
WILLIAM W. DAVIS      
William W. Davis

 

Senior Vice President and Chief
Financial Officer (Principal Financial and Accounting Officer)

 

March 21, 2003

53



CERTIFICATIONS

        I, Barry E. Davis, President and Chief Executive Officer of Crosstex Energy GP, LLC, the general partner of Crosstex Energy GP, L.P., the general partner of the registrant, certify that:

1.
I have reviewed this annual report on Form 10-K of Crosstex Energy, L.P.;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and:

(a)
designated such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

(c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

(b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

 

/s/  
BARRY E. DAVIS      
Barry E. Davis,
President and Chief Executive Officer
(principal executive officer)

54


        I, William W. Davis, Senior Vice President and Chief Financial Officer of Crosstex Energy GP, LLC, the general partner of Crosstex Energy GP, L.P., the general partner of the registrant, certify that:

1.
I have reviewed this annual report on Form 10-K of Crosstex Energy, L.P.;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and:

(a)
designated such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

(c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

(b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

 

/s/  
WILLIAM W. DAVIS      
William W. Davis,
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)

55



INDEX TO FINANCIAL STATEMENTS

Crosstex Energy, L.P. Financial Statements:    

 

 

Report of Independent Auditors

 

F-2

 

 

Consolidated Balance Sheets as of December 31, 2002 and 2001

 

F-3

 

 

Consolidated Statements of Operations for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000 and the four months ended April 30, 2000 (Predecessor)

 

F-4

 

 

Consolidated Statements of Changes in Partners' Equity for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000 and the four months ended April 30, 2000 (Predecessor)

 

F-5

 

 

Consolidated Statements of Comprehensive Income for the years ended December 31, 2002 and 2001

 

F-6

 

 

Consolidated Statements of Cash Flows for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000 and the four months ended April 30, 2000 (Predecessor)

 

F-7

 

 

Notes to Consolidated Financial Statements

 

F-8

Financial Statement Schedule:

 

 

 

 

II—Valuation and Qualifying Accounts for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000, and the four months ended April 30, 2000 (Predecessor)

 

S-1

F-1



Independent Auditors' Report

The Partners
Crosstex Energy, L.P.:

We have audited the accompanying consolidated balance sheets of Crosstex Energy, L.P. (a Delaware limited partnership and successor to Crosstex Energy Services, Ltd.) and subsidiaries as of December 31, 2002 and 2001 and the related consolidated statements of operations, changes in partners' equity, comprehensive income, and cash flows for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000, and the four months ended April 30, 2000 (Predecessor). In connection with the audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Crosstex Energy, L.P. and subsidiaries as of December 31, 2002 and 2001, and the consolidated results of their operations, comprehensive income, and their cash flows for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000, and the four months ended April 30, 2000 (Predecessor) in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects the information set forth therein.

As explained in note 2 to the consolidated financial statements, effective January 1, 2001, the Partnership changed its method of accounting for derivatives. Also, as explained in note 2, effective January 1, 2002, the Partnership changed its method of amortizing goodwill.

Dallas, Texas
February 7, 2003

F-2



CROSSTEX ENERGY, L.P.

(Successor to Crosstex Energy Services, Ltd.)

Consolidated Balance Sheets

December 31, 2002 and 2001
(In thousands)

 
  2002
  2001
 
Assets  
Current assets:            
  Cash and cash equivalents   $ 1,308   352  
  Accounts receivable:            
    Trade     104,802   58,222  
    Imbalances     79   117  
    Related party       418  
    Other     637   192  
  Assets from risk management activities     2,947   3,361  
  Prepaid expenses and other     1,225   1,865  
   
 
 
      Total current assets     110,998   64,527  
   
 
 
Property and equipment:            
  Transmission assets     50,391   33,559  
  Gathering systems     22,624   12,541  
  Gas plants     39,475   37,373  
  Other property and equipment     2,754   2,692  
  Construction in process     6,935   5,092  
   
 
 
      Total property and equipment     122,179   91,257  
  Accumulated depreciation     (12,231 ) (6,306 )
   
 
 
      Total property and equipment, net     109,948   84,951  
Account receivable from Enron (net of allowance of $5,776 in 2001)       2,467  
Assets from risk management activities     155   117  
Intangible assets, net     5,340   9,678  
Goodwill, net     4,873   4,873  
Investment in limited partnerships     346   534  
Other assets, net     778   1,229  
   
 
 
      Total assets   $ 232,438   168,376  
   
 
 

Liabilities and Partners' Equity

 
Current liabilities:            
  Accounts payable and accrued gas purchases   $ 110,793   56,092  
  Accrued imbalances payable     149   422  
  Liabilities from risk management activities     4,006   7,565  
  Current portion of long-term debt     50    
  Other current liabilities     4,672   2,702  
   
 
 
      Total current liabilities     119,670   66,781  
   
 
 
Long-term debt     22,500   60,000  
Liabilities from risk management activities     271   440  
Liability from interest rate swap     181    
Partners' equity:            
  Predecessor partners' equity       41,013  
  Common unitholders (2,633,000 units issued and outstanding at December 31, 2002)     58,147    
  Subordinated unitholders (4,667,000 units issued and outstanding at December 31, 2002)     31,829    
  General partner interest (2% interest with 149,000 equivalent units outstanding at December 31, 2002)     1,016    
  Other comprehensive income (loss)     (1,176 ) 142  
   
 
 
      Total partners' equity     89,816   41,155  
   
 
 
      Total liabilities and partners' equity   $ 232,438   168,376  
   
 
 

See accompanying notes to consolidated financial statements.

F-3



CROSSTEX ENERGY, L.P.

(Successor to Crosstex Energy Services, Ltd.)

Consolidated Statements of Operations

(In thousands)

 
   
   
   
  (Predecessor)
 
 
  Years ended December 31,
   
 
 
  Eight months
ended
December 31,
2000

  Four months
ended
April 30,
2000

 
 
  2002
  2001
 
Revenues:                    
  Midstream   $ 437,676   362,673   88,008   3,591  
  Treating     14,817   24,353   17,392   5,947  
   
 
 
 
 
    Total revenues     452,493   387,026   105,400   9,538  
   
 
 
 
 
Operating costs and expenses:                    
  Midstream purchased gas     413,982   344,755   83,672   2,746  
  Treating purchased gas     5,767   18,078   14,876   4,731  
  Operating expenses     10,468   7,430   1,796   544  
  General and administrative     8,454   5,914   2,010   810  
  Stock based compensation     41       8,802  
  Impairments     4,175   2,873      
  (Profit) loss on energy trading contracts     (2,703 ) 3,714   (1,253 ) (638 )
  Depreciation and amortization     7,745   6,101   2,261   522  
   
 
 
 
 
    Total operating costs and expenses     447,929   388,865   103,362   17,517  
   
 
 
 
 
    Operating income (loss)     4,564   (1,839 ) 2,038   (7,979 )
Other income (expense):                    
  Interest expense, net     (2,717 ) (2,253 ) (530 ) (79 )
  Other income     155   174   115   381  
   
 
 
 
 
    Total other income (expense)     (2,562 ) (2,079 ) (415 ) 302  
   
 
 
 
 
    Net income (loss)   $ 2,002   (3,918 ) 1,623   (7,677 )
   
 
 
 
 
Allocation of 2002 net income:                    
  Net income for the period from January 1, 2002 to December 16, 2002   $ 1,682        
  Net income for the period from December 17, 2002 to December 31, 2002     320        
   
 
 
 
 
    Net income   $ 2,002        
   
 
 
 
 
General partner interest in net income for the period from December 17, 2002 to December 31, 2002   $ 6        
   
 
 
 
 
Limited partners' interest in net income for the period from December 17, 2002 to December 31, 2002   $ 314        
   
 
 
 
 
Net income per limited partners' unit:                    
  Basic and diluted   $ .04        
   
 
 
 
 
Weighted average limited partners' units outstanding     7,300        
   
 
 
 
 

See accompanying notes to consolidated financial statements.

F-4



CROSSTEX ENERGY, L.P.
(Successor to Crosstex Energy Services, Ltd.)

Consolidated Statements of Changes in Partners' Equity

Years ended December 31, 2002 and 2001, eight months ended December 31, 2000, and
four months ended April 30, 2000

(In thousands)

 
   
   
   
   
   
  Total
 
Balance, December 31, 1999                         $ 3,242  
Capital contributions                           45  
Equity based compensation                           7,999  
Net loss                           (7,677 )
                         
 
Balance April 30, 2000 (Predecessor)                         $ 3,609  
                         
 



 
 
  Crosstex
Energy
Services, Ltd.
Partners'
equity

  Crosstex Energy L.P.
   
   
 

 

 

Common
units


 

Subordinated
units


 

General
partner
interest


 

Other
comprehensive
income


 

Total


 
Balance May 5, 2000   $              
Contributions of assets and liabilities of predecessor     21,903             21,903  
Capital contributions     16,828             16,828  
Net income     1,623             1,623  
   
 
 
 
 
 
 
Balance, December 31, 2000     40,354             40,354  
Capital contributions     5,019             5,019  
Distributions     (442 )           (442 )
Net loss     (3,918 )           (3,918 )
Cumulative adjustment from adoption of accounting standard             (1,006 )   (1,006 )
Hedging gains or losses reclassified to earnings             1,006     1,006  
Adjustment in fair value of derivatives             142     142  
   
 
 
 
 
 
 
Balance, December 31, 2001     41,013         142     41,155  
Assets not contributed to Crosstex Energy, L.P.     (3,754 )           (3,754 )
Capital contributions     14,000             14,000  
Stock based compensation     41             41  
Neet income from January 1, 200 through December 16, 2002     1,682             1,682  
Distributions     (2,500 )           (2,500 )
Transfer of equity in accordance with initial public offering     (50,482 ) 17,844   31,628   1,010        
Net proceeds from initial public offering       40,190           40,190  
Net income from December 17, 2002 through December 31, 2002       113   201   6       320  
Hedging gains or losses reclassified to earnings             (178 )   (178 )
Adjustment in fair value of derivatives             (1,140 )   (1,140 )
   
 
 
 
 
 
 
Balance, December 31, 2002   $   58,147   31,829   1,016   (1,176 )   89,816  
   
 
 
 
 
 
 

See accompanying notes to consolidated financial statements.

F-5



CROSSTEX ENERGY, L.P.
(Successor to Crosstex Energy Services, Ltd.)

Consolidated Statements of Comprehensive Income

December 31, 2002 and 2001

(In thousands)

 
  2002
  2001
 
Net (loss) income   $ 2,002   (3,918 )
Cumulative adjustment from adoption of accounting standard       (1,006 )
Hedging gains or losses reclassified to earnings     (178 ) 1,006  
Adjustment in fair value of derivatives     (1,140 ) 142  
   
 
 
  Comprehensive income (loss)   $ 684   (3,776 )
   
 
 

See accompanying notes to consolidated financial statements.

F-6



CROSSTEX ENERGY, L.P.
(Successor to Crosstex Energy Services, Ltd.)

Consolidated Statements of Cash Flows

(In thousands)

 
   
   
   
  (Predecessor)

 
 
  Years ended December 31,
   
  Four months
ended
April 30,
2000

 
 
  Eight months ended
December 31,
2000

 
 
  2002
  2001
 
Cash flows from operating activities:                    
  Net income (loss)   $ 2,002   (3,918 ) 1,623   (7,677 )
  Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:                    
    Depreciation, depletion, and amortization     7,745   6,101   2,261   522  
    Impairments     4,175   2,873      
    Income (loss) on investment in affiliated partnerships     41   (35 ) (48 ) (15 )
    Noncash stock based compensation     41       7,999  
    Loss on sale of assets            
    Changes in assets and liabilities:                    
      Accounts receivable     (46,544 ) 47,565   (83,668 ) (994 )
      Prepaid expenses     178   (1,566 ) 108   (328 )
      Accounts payable, accrued gas purchases, and other accrued liabilities     54,427   (63,115 ) 87,442   8,129  
      Risk management activities     (4,669 ) 4,573   (47 )  
      Other     2,560   (804 ) 70   (256 )
   
 
 
 
 
        Net cash provided by (used in) operating activities     19,956   (8,326 ) 7,741   7,380  
   
 
 
 
 
Cash flows from investing activities:                    
  Additions to property and equipment     (14,545 ) (22,685 ) (4,667 ) (3,026 )
  Proceeds from disposition of assets           100  
  Asset purchases     (18,785 ) (30,003 ) (21,133 )  
  Distributions from affiliated partnerships     90   153   157   77  
   
 
 
 
 
        Net cash used in investing activities     (33,240 ) (52,535 ) (25,643 ) (2,849 )
   
 
 
 
 
Cash flows from financing activities:                    
  Proceeds from bank borrowings     384,050   267,131   51,950   7,000  
  Payments on bank borrowings     (421,500 ) (229,150 ) (36,950 ) (6,847 )
  Predecessor cash         4,729    
  Distribution to partners     (2,500 ) (442 )    
  Net proceeds from initial pulic offering     40,190        
  Contribution from partners     14,000   5,019   16,828   45  
   
 
 
 
 
        Net cash provided by financing activities     14,240   42,558   36,557   198  
   
 
 
 
 
        Net increase (decrease) in cash and cash equivalents     956   (18,303 ) 18,655   4,729  

Cash and cash equivalents, beginning of period

 

 

352

 

18,655

 


 


 
   
 
 
 
 
Cash and cash equivalents, end of period   $ 1,308   352   18,655   4,729  
   
 
 
 
 
Cash paid for interest   $ 2,558   2,720   507   144  
Noncash transactions—stock based compensation     41       7,999  
Contributions of assets and liabilities of predecessor         21,903    
Assets not contributed to Crosstex Energy, L.P.     3,754        

See accompanying notes to consolidated financial statements.

F-7



CROSSTEX ENERGY, L.P.

(Successor to Crosstex Energy Services, Ltd.)

Notes to Consolidated Financial Statements

December 31, 2002 and 2001

(1) Organization and Summary of Significant Agreements

        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 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.

        On December 17, 2002, the Partnership completed an initial public offering of common units representing limited partner interests in the Partnership. Prior to its initial public offering, the Partnership was an indirect wholly owned subsidiary of Crosstex Energy Holdings Inc. (Crosstex Holdings). Crosstex Holdings conveyed to the Partnership its indirect wholly owned ownership interest in Crosstex Energy Services, Ltd. (CES) in exchange for (i) a 2% general partner interest (including certain Incentive Distribution Rights) in the Partnership, (ii) 333,000 common units and (iii) 4,667,000 subordinated units of the Partnership. Prior to the conveyance of CES to the Partnership, CES distributed certain assets to Crosstex Holdings including (i) the Jonesville and Clarkson gas plants, (ii) the Enron receivable and related derivative positions, and (iii) the right to receive a cash distribution of $2.5 million.

        CES constitutes the Partnership's predecessor. The transfer of ownership interests in CES to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Accordingly, the accompanying financial statements include the historical results of operations of CES prior to transfer to the Partnership.

        Crosstex Energy Services, Ltd. (the Predecessor), a Texas limited partnership was formed on December 19, 1996, to engage in the gathering, transmission, treating, processing, and marketing of natural gas.

        Effective May 5, 2000, Crosstex Holdings acquired a 100% interest in Crosstex Energy, Inc. (CEI), the general partner of the Predecessor, and a 100% limited partnership interest in the Predecessor. Also, effective May 5, 2000, the Predecessor was dissolved and Crosstex Holdings formed a new partnership, Crosstex Energy Services, Ltd. (CES), with the same management organization and purpose as the Predecessor. CEI was the managing and sole general partner and held a 1% interest in CES.

        Crosstex Holdings is majority owned by Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. (collectively, Yorktown). Yorktown paid $21.6 million cash to capitalize Crosstex Holdings in exchange for 100% of the common stock of Crosstex Holdings. Subsequently, Crosstex

F-8



Holdings issued 722,771 shares of common stock to the management group of the Predecessor and CES in return for their 36.5% effective interest, resulting in CES management owning 25% of Crosstex Holdings and Yorktown owning the remaining 75%.

        The accompanying consolidated financial statements include the results of operations of CES subsequent to the Yorktown transactions as of May 5, 2000.

        Periods presented prior to May 5, 2000, relate to the Predecessor, and are not comparable in all respects to CES' financial statements due to a new basis of accounting established in connection with the Yorktown transaction.

        The purchase price of $21.9 million was comprised of $13.9 million paid by Yorktown for an approximate 63.5% interest in the Predecessor and $800,000 cash and 722,711 shares of common stock of Crosstex Holdings valued at approximately $7.2 million issued to management in exchange for an approximate 36.5% economic interest held by management in the Predecessor. The purchase price of Crosstex Holdings which was pushed down to CES was allocated based on an estimated fair values as follows (in thousands):

Working capital   $ (9,604 )
Property, plant, and equipment     11,804  
Intangible assets     14,167  
Goodwill     4,754  
Investments     782  
   
 
    $ 21,903  
   
 

        Concurrent with the purchase of the Predecessor and the formation of CES, Crosstex Holdings contributed an additional $6.8 million as partner capital to CES for use as working capital and later during 2000 contributed another $10.0 million as partner capital.

        The accompanying consolidated financial statements include the assets, liabilities, and results of operations of the Predecessor prior to May 5, 2000 and the Partnership (or CES as its predecessor) and its wholly owned subsidiaries thereafter. The consolidated operations are hereafter referred to herein collectively as the "Partnership." All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for the prior year to conform to the current presentation.

(2) Significant Accounting Policies

        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

F-9


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 considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

        Property, plant, and equipment consist of intrastate gas transmission systems, gas gathering systems, industrial supply pipelines, natural gas processing plants, and gas treating plants.

        Other property and equipment is primarily comprised of furniture, fixtures, and office equipment. Such items are depreciated over their estimated useful life of five years. Property, plant, and equipment are recorded at cost, including capitalized interest. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets. Depreciation is provided using the straight-line method based on the estimated useful life of each asset, as follows:

 
  Useful lives
Transmission assets   15 years
Gathering systems   7-15 years
Gas plants   10-15 years
Other property and equipment   5 years

        Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires long-lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the Partnership compares the net book value of the asset to the undiscounted expected future net cash flows. If impairment has occurred, the amount of such impairment is determined based on the expected future net cash flows discounted using a rate commensurate with the risk associated with the asset. Impairments of approximately $4,175,000 and $2,873,000 associated with certain assets and the related intangible assets were recorded in the years ended December 31, 2002 and 2001, respectively. The impairments recorded in 2002 and 2001 relate primarily to customer relationships recorded as intangible assets as part of the Yorktown transaction. Due to changes impacting the expected future cash flows of the related assets, the Partnership determined the intangible assets were impaired under SFAS No. 121 or SFAS No. 144.

        When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions

F-10



regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which would require us to record an impairment of an asset.

        Until January 1, 2002, goodwill was amortized over the period of expected benefit. Goodwill related to the Yorktown transaction was being amortized on a straight-line basis over 15 years (see note 1). Such amortization was $296,000 for the year ended December 31, 2001. As discussed in note 2(n), the Partnership discontinued the amortization of goodwill effective January 1, 2002, with the adoption of SFAS No. 142.

        Intangible assets are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which average 15 years. Such amortization was approximately $454,000 and $772,000 for the years ended December 31, 2002 and 2001, respectively. See impairment of intangibles discussed in note 2(c).

        Quantities of natural gas over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time the imbalance was created. These imbalances are typically settled with deliveries of natural gas. The Partnership had an imbalance payable of $149,000 and $422,000, and an imbalance receivable of $79,000 and $117,000 at December 31, 2002 and 2001, respectively. Imbalances are carried at the lower of cost or market value.

        The Partnership recognizes revenue for sales or services at the time the natural gas or NGLs are delivered or at the time the service is performed. See discussion of accounting for energy trading activities in note 2(h).

        The Partnership engages in price risk management activities in order to minimize the risk from market fluctuation in the price of natural gas and NGLs. To qualify as a hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statements of operations as a cost of gas purchased.

        Prior to January 1, 2001, these agreements were accounted for as hedges using the deferral method of accounting. Unrealized gains and losses were generally not recognized until the physical production required by the contracts was delivered. At the time of delivery, the resulting gains and

F-11



losses were recognized as an adjustment to natural gas revenues. The cash flows related to any recognized gains or losses associated with these hedges were reported as cash flows from operations. If the hedge was terminated prior to maturity, gains or losses were deferred and included in income in the same period as the physical production required by the contracts was delivered.

        Effective January 1, 2001, the Partnership adopted Statement of Financial Accounting Standards No. 133 (SFAS 133), Accounting for Derivative Instruments and Hedging Activities. This standard requires recognition of all derivative and hedging instruments in the statements of financial position as either assets or liabilities and measures them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

        To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The impact of adopting SFAS No. 133 on January 1, 2001, was to record the fair value of derivatives as a liability in the amount of $1,006,000.

        Currently, all derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. These instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in other comprehensive income in partners' equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. The asset or liability related to the derivative instruments is recorded on the balance sheet in assets or liabilities from risk management activities. Any ineffective portion of the gain or loss is recognized in earnings immediately.

        The Partnership conducts "off-system" gas marketing operations as a service to producers on systems that the Partnership does not own. The Partnership refers to these activities as part of Producer Services. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, the Partnership purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas.

        The Partnership manages its price risk related to future physical purchase or sale commitments for its Producer Services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance the Partnership's future commitments and significantly reduce its risk to the movement in natural gas prices. However, the Partnership is subject to counterparty risk for both the physical and financial contracts. Prior to October 26, 2002, the Partnership accounted for its Producer Services natural gas marketing activities as energy trading contracts in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 required energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. In October 2002, the EITF reached a consensus to rescind

F-12



EITF No. 98-10. Accordingly, energy trading contracts entered into subsequent to October 25, 2002, should be accounted for under accrual accounting rather than mark-to-market accounting unless the contracts meet the requirements of a derivative under SFAS No. 133. The Partnership's energy trading contracts qualify as derivatives, and accordingly, the Partnership continues to use mark-to-market accounting for both physical and financial contracts of its Producer Services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to the Partnership's Producer Services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

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

        Margins earned on settled contracts from its producer services activities included in (profit) loss on energy trading contracts in the consolidated statement of operations was ($1,791), ($1,946), ($1,206), and ($638) for the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000 and the four months ended April 30, 2000, respectively.

        Energy trading contract volumes that were physically settled were as follows (in MMBtus):

 
  Years ended December 31,
  Eight months
ended
December 31,
2000

  Four months
ended
April 30,
2000

 
  2002
  2001
Volumes purchased and sold   84,069,368   103,330,628   51,993,614   26,525,486

        During 1998, the Partnership adopted SFAS 130, Reporting Comprehensive Income, which establishes standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, unrealized gains and losses on marketable securities, foreign currency translation adjustments, minimum pension liability adjustments, and effective January 1, 2001, unrealized gains and losses on derivative financial instruments. For the periods prior to January 1, 2001, comprehensive income and net income were equal and thus, SFAS No. 130 had no effect on the financial statements.

        With the adoption of SFAS No. 133 on January 1, 2001, the Partnership began recording deferred hedge gains and losses on its derivative financial instruments that qualify as hedges as other comprehensive income.

        No provision is made in the accounts of the Partnership for federal or state income taxes because such taxes are liabilities of the individual partners, and the amounts thereof depend upon their

F-13


respective tax situations. The tax returns and amounts of allocable Partnership revenues and expenses are subject to examination by federal and state taxing authorities. If such examinations result in changes to allocable Partnership revenues and expenses, the tax liability of the Partners could be changed accordingly.

        Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist primarily of trade accounts receivable and derivative financial instruments. Management believes the risk is limited, as the Partnership's customers represent a broad and diverse group of energy marketers and end users. In addition, the Partnership continually monitors and reviews credit exposure to its marketing counterparties and letters of credit or other appropriate security are obtained as considered necessary to limit the risk of loss. As of December 31, 2002 and 2001, the reserve for doubtful accounts was approximately $0 and $5.8 million, respectively. See note 10 for further discussion.

        During the years ended December 31, 2002 and 2001, eight months ended December 31, 2000 and four months ended April 30, 2000, the Partnership had 1, 3, 3, and 2 customers, respectively, which individually accounted for more than 10% of consolidated revenues. The relevant percentages for these customers were: (i) for the year ended December 31, 2002—27.5%; (ii) for the year ended December 31, 2001—23.9%, 13.4%, and 11.5%; (iii) for the eight months ended December 31, 2000—28.8%, 20.7%, and 14.1%; and (iv) for the four months ended April 30, 2000—50.4% and 21.1%. While these customers represent a significant percentage of revenues, the loss of any of these would not have a material adverse impact on the Partnership's results of operations.

        Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that related to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. For years ended December 31, 2002 and 2001, eight months ended December 31, 2000, and four months ended April 30, 2000 such expenditures were not significant.

        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 plan. In accordance with APB No. 25, compensation is recorded to the extent the fair value of the stock exceeds the exercise price of the option at the measurement date. Compensation expense of $41,000, $0, and $0 was recognized in 2002, 2001, and 2000, respectively.

F-14


        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 (loss) would have been as follows:

 
  Year ended December 31,
  Eight months ended December 31, 2000
 
  2002
  2001
Net income, as reported   $ 2,002   (3,918 ) 1,623
Add: Stock-based employee compensation expense included in reported net income     41    
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards     328   226   103
   
 
 
Pro forma net income   $ 1,715   (4,144 ) 1,520
   
 
 

        Actual and pro forma earnings per unit for the period December 17, 2002 through December 31, 2002 would have been $0.04 per unit.

        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 grants in 2002, 2001, and 2000:

 
  Crosstex Holdings
   
 
  Crosstex Energy, L.P.
 
  2002
  2001
  2000
Dividend yield     0%   0%   0%   10%
Expected volatility     0%   0%   0%   24%
Risk free interest rate     4.1%   5.8%   6.9%   2.2%
Expected life     3 years   3 years   3 years   3 years
Contractual life     3   3.6   4.6   10
Weighted average of fair value of unit options granted   $       1.15
Fair value of $10 stock options granted     3.17   3.27   2.04  
Fair value of $12 stock options granted     1.40   1.52    
Fair value of $14 stock options granted     .91      

        In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations, requiring business combinations entered into after June 30, 2001, to be accounted for using the purchase method of accounting. Specifically identifiable intangible assets acquired, other than goodwill, will be amortized over their estimated useful economic life. This pronouncement had no effect on the Partnership's financial position or results of operations.

        In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for

F-15



impairment at least annually. In addition, SFAS No. 142 requires that the Partnership identity reporting units for purposes of assessing potential future impairments of goodwill, reassess the useful lives of other existing recognized intangible assets, and cease amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with the guidance in SFAS No. 142. This statement is required to be applied in the fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS No. 142 required the Partnership to complete a transitional goodwill impairment test within six months from the date of adoption and reassess the useful lives of other intangible assets within the first interim quarter after adoption. The Partnership had $4,873,000 recorded for goodwill, net of accumulated amortization at December 31, 2001 and recorded goodwill amortization expense of $296,000 for the year ended December 31, 2001.

        The following table shows the Partnership's net earnings excluding goodwill amortization for the years ended December 31, 2002 and 2001, eight months ended December 31, 2000, and four months ended April 30, 2000.

 
  Years ended December 31,
   
   
 
 
  Eight months
ended
December 31,
2000

   
 
 
  Four months ended
April 30,
2000

 
 
  2002
  2001
 
 
  (In thousands)

 
Reported net income (loss)   $ 2,002   (3,918 ) 1,623   (7,677 )
Goodwill amortization       296   178   22  
   
 
 
 
 
  Adjusted net income (loss)   $ 2,002   (3,622 ) 1,801   (7,655 )
   
 
 
 
 

        In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement establishes standards for accounting for obligations associated with the retirement of tangible long-lived assets. This standard is required to be adopted by the Partnership beginning on January 1, 2003. The Partnership does not presently have any significant asset retirement obligations, and accordingly, the adoption of SFAS No. 143 is not expected to have a significant impact on our results of operations or financial condition.

        In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 addresses financial accounting and reporting for impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. This statement also amends APB No. 51, Consolidated Financial Statements, to eliminate the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. See the impact of the adoption of SFAS No. 144 at note 2(c).

        In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be

F-16



recognized when the liability is incurred rather than when the entity commits to an exit plan. This standard is effective for all exit or disposal activities which are initiated after December 31, 2002. The Partnership does not anticipate the adoption of SFAS 146 will have any impact its financial position or results of operations.

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

        In June 2002, the Emerging Issues Task Force (EITF) reached consensus on certain issues in EITF Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts. Consensus was reached on two issues: 1) that gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the statement of operations, and 2) that entities should disclose the types of contracts that are accounted for as energy trading contracts along with a variety of other data regarding values, sensitivity to changes in estimates, maturity dates, and other factors. The Partnership early adopted this consensus in the second quarter of 2002 and all comparative financial statements were reclassified to report gains or losses on energy trading contracts net in the statements of operations. In October 2002, the EITF reached a consensus to rescind EITF 98-10. Accordingly, energy related contracts that are not accounted for pursuant to SFAS No. 133 should be accounted for as executory contracts and carried on an accrual basis, not fair value. The consensus should be applied prospectively to all new energy trading contracts entered into after October 25, 2002 and to all contracts that existed on October 25, 2002, in periods beginning after December 15, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principles. The rescission of EITF 98-10 did not have any significant effect on the Partnership's financial position or results of operations.

        In January 2003, the FASB issued FASB Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement provisions of the Interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ending after December 15, 2002. The adoption of the statement is not expected to have a material effect on the Partnership's financial statements when adopted.

F-17



        In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. FIN No. 46 requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this Interpretation must be applied at the beginning of the first interim or annual period beginning after June 15, 2003. The Partnership is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of Fin No. 46 will not have an impact on its financial statements.

(3) Significant Asset Purchases

        On August 16, 2000, CES entered into a purchase and sale agreement with Western Gas Resources, Inc. to acquire certain natural gas gathering and related facilities known as the Arkoma System for a total purchase price of $10,500,000, which was allocated entirely to transmission assets. CES recorded the net assets acquired based on relative fair values, and CES's results of operations include the results of the Arkoma System as of September 1, 2000.

        On September 14, 2000, CES entered into a purchase and sale agreement with Tejas Hydrocarbons LLC to acquire all of the assets of GC Marketing Company (a Texas general partnership), for a total purchase price of $10,632,209, after closing adjustments. CES recorded the net assets acquired based on relative fair values and the CES's results of operations include the results of GC Marketing Company as of October 1, 2000.

        The purchase price consisted of the following (in thousands):

Transmission assets   $ 10,716  
Other property, plant, and equipment     131  
Miscellaneous liabilities     (215 )
   
 
    $ 10,632  
   
 

        On April 3, 2001, CES entered into a purchase and sale agreement with Tejas Energy NS, LLC to acquire all of the assets of Tejas Texas Pipeline GP, LLC, a Delaware limited liability company, and Tejas C Pipeline LP, LLC, a Delaware limited liability company, for a total purchase price of $30,003,120, after closing adjustments. CES recorded the net assets acquired based on relative fair values, and CES's results of operations include the results of operations of the acquired assets as of May 1, 2001.

F-18



        The purchase price consisted of the following (in thousands):

Gas plant   $ 11,837
Gathering systems     10,192
Transmission assets     7,158
Other property, plant, and equipment     816
   
    $ 30,003
   

        On October 11, 2001, CES entered into a purchase and sale agreement with various individuals to acquire the common stock of Millennium Gas Services, Inc. (Millennium) for a total of $2,124,217 after closing adjustments, which was allocated entirely to treating plants. CES's results of operations include the results of Millennium as of October 1, 2001.

        On June 6, 2002, CES acquired 70 miles of then-inactive pipeline from Florida Gas Transmission Company for $1,474,000 in cash and a $800,000 note payable. On June 7, 2002, CES acquired the Pandale gathering system which is connected to two treating plants, one of which (the "Will-O-Mills" Plant) was half-owned by the Partnership, from Star Field Services for $2,156,000 in cash. The Partnership purchased the other one-half interest in the Will-O-Mills Plant on December 30, 2002 for $2,200,000 in cash.

        On December 19, 2002, CES acquired the Vanderbilt system, consisting of approximately 200 miles of gathering pipeline located near our Gulf Coast System from an indirect subsidiary of Devon Energy Corporation, for $12,000,000 cash.

(4) Investment in Limited Partnerships

        The Partnership owns a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Company (CPC), a 20.31% interest as a limited partner in CPC, and a 50% interest in the J.O.B. J.V. The Partnership accounts for its investments under the equity method, as it exercises significant influence in operating decisions as a general partner. Under this method, the Partnership records its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them are recorded as a reduction in the Partnership's investment in the affiliated partnership.

(5) Long-Term Debt

        In February 2000, the Predecessor and Union Bank of California, N.A. (UBOC) entered into a $22 million secured credit facility, which was amended in May 2000 for the creation of CES. In August 2000, the Partnership and UBOC amended the credit facilities to create a Revolver A of $22 million and a Revolver B of $12 million. Revolver A was available for general corporate purposes, including the acquisition and installation of property and equipment. Revolver B was available to finance letters of credit and certain working capital requirements. In December 2001, the credit facilities were amended to increase the availability under Revolver A to $60 million and Revolver B to $15 million, thereby increasing the credit facilities to $75 million.

F-19



        In connection with the Partnership's initial public offering, the Partnership amended the secured credit facility to provide a $67.5 million credit facility consisting of:

        The acquisition facility will be used to finance the acquisition and development of gas gathering, treating, and processing facilities, as well as general partnership purposes. At December 31, 2002, $21.8 million was outstanding under the acquisition facility, leaving approximately $25.7 available for future borrowings. The acquisition facility will convert into a term loan on April 30, 2004, and we will be required to make eleven quarterly payments equal to 5% of outstanding borrowings. The first such payment will be due in July 2004. The term loan will mature in April 2007, at which time it will terminate and all outstanding amounts shall be due and payable. Prior to April 30, 2004, amounts borrowed and repaid under the acquisition credit facility may be reborrowed.

        The working capital facility will be used for ongoing working capital needs, letters of credit, distributions and general partnership purposes, including future acquisitions and expansions. At December 31, 2002, $13.1 million of letters of credit were issued under the working capital facility, leaving approximately $6.9 million available for future issuances of letters of credit, or up to $5 million of cash borrowings. The aggregate amount of borrowings under the working capital facility is subject to a borrowing base requirement relating to the amount of our cash and eligible receivables (as defined in the credit agreement), and there is a $5.0 million sublimit for cash borrowings. This facility will mature in April 2004, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital facility may be reborrowed. We will be required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once a year.

        Our obligations under the credit facility are secured by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of our equity interests in certain of our subsidiaries. The credit agreement is guaranteed by certain of our subsidiaries. We may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs.)

        Indebtedness under the acquisition facility and the working capital facility bear interest at our option at the administrative agent's reference rate plus 0.125% to 1.375% or LIBOR plus 1.625% to 2.875%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.50% to 2.00% per annum, plus a fronting fee of 0.125% per annum. We incur quarterly commitment fees based on the unused amount of the credit facilities.

F-20



        The credit agreement prohibits us from declaring distributions to unitholders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. In addition, the credit agreement limits our operating partnership's ability to:

        The credit facility contains the following covenants requiring us to maintain:

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

        In June 2002, as part of the purchase price of Florida Gas Transmission Company (FGTC), the Partnership issued a note payable for $800,000 to FGTC that is payable in $50,000 increments starting June 2003 through June 2006 with a final payment of $600,000 due in June 2007. The note bears interest payable annually at LIBOR plus 1%.

F-21



        As of December 31, 2002 and 2001, long-term debt consisted of the following (in thousands):

 
  2002
  2001
Revolver A Facility, interest based on prime, interest rate at December 31, 2001 was 5.75%   $   17,500
Revolver A Facility, based on LIBOR interest rate at December 31, 2001 was 4.67%       10,500
Revolver A Facility, based on LIBOR, interest rate at December 31, 2001 was 4.40%       32,000
Acquisition credit facility, interest based at prime plus 0.625%, interest rate at December 31, 2002 was 4.88%     1,750  
Acquisition credit facility, interest based on LIBOR plus 2.125%. Interest rate at December 31, 2002 was 3.95%     20,000  
Note payable to Florida Gas Transmission Company     800  
   
 
      22,550   60,000
Less current portion     50  
   
 
  Debt classified as long-term   $ 22,500   60,000
   
 

        Maturities for the long-term debt as of December 31, 2002 are as follows (in thousands):

2003   $ 50
2004     2,225
2005     4,400
2006     4,400
2007     11,475
Thereafter    

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

(6) Partners' Capital

        On December 17, 2002, the Partnership completed its initial public offering of 2,300,000 common units representing limited partner interests at a price of $20.00 per common unit. Total proceeds from the sale of the 2,300,000 units were $46.0 million, before offering costs and underwriting commissions.

F-22


Concurrent with the closing of the initial public offering, the Partnership entered into a $67.5 million credit facility with a syndicate of banks led by Union Bank of California, that provides for a $47.5 million acquisition credit facility and a $20 million working capital facility (see note 5). On December 17, 2002, the Partnership had borrowings of $20 million under the acquisition credit facility.

        A summary of the proceeds received from the offering and the use of those proceeds is as follows (in thousands):

Proceeds received:      
  Sale of common units   $ 46,000
   
Use of proceeds:      
  Underwriters' fees   $ 3,220
  Professional fees and other offering costs     2,590
  Repayment of debt     33,000
  Distribution to Crosstex Holdings     2,500
  Working capital     4,690
   
      Total use of proceeds   $ 46,000
   

        The Crosstex Energy, L.P. partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts.

        During the subordination period, the Partnership may issue up to 1,316,500 additional common units or an equivalent number of securities ranking on a parity with the common units without obtaining unitholder approval. The Partnership may also issue an unlimited number of common units during the subordination period for acquisitions, capital improvements or debt repayments that increase cash flow from operations per unit on a pro forma basis.

        The subordination period will end once the Partnership meets the financial tests in the partnership agreement, but it generally cannot end before December 31, 2007. When the subordination period ends, each remaining subordinated unit will convert into one common unit and the common units will no longer be entitled to arrearages.

        If the Partnership meets the applicable financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after December 31, 2005, 25% of the subordinated units will convert to common units. If the Partnership meets these tests for any three consecutive four-quarter periods ending on or after December 31, 2006, an additional 25% of the subordinated units will convert to common units. The early conversion of the second 25% of the subordinated units

F-23


may not occur until at least one year after the early conversion of the first 25% of the subordinated units.

        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 commencing with the quarter ending on March 31, 2003. 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. If cash distributions exceed $0.50 per unit in a quarter, the general partner will receive incentive distributions up to 50% of the cash distributed in excess of $0.50 per unit. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.50 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.

(7) Retirement Plans

        The Partnership sponsors a single employer 401(k) plan for employees who become eligible upon the date of hire. The Partnership, as stated within the plan document, will make discretionary contributions at the end of the year. There were no contributions during the eight months ended December 31, 2000 and the four months ended April 30, 2000. Contributions for the years ended December 31, 2002 and 2001 totaled $198,000 and $116,000, respectively.

(8) Employee Incentive Plans

        In December 2002, the Partnership's managing general partner adopted a long-term incentive plan for its employees, directors, and affiliates who perform services for the Partnership. The plan currently permits the grant of awards covering an aggregate of 700,000 common units, 233,000 of which may be awarded in the form of restricted units and 467,000 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the managing general partner's board of directors.

        A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. In addition, the restricted units will become exercisable upon a change of control of the Partnership, its general partner, or managing general partner.

        The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units.

F-24



Therefore, plan participants will not pay any consideration for the common units they receive and the Partnership will receive no remuneration for the units.

        As of December 31, 2002, there were no restricted units issued under the long-term incentive plan.

        Unit options will have an exercise price that, in the discretion of the compensation committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, unit options will become exercisable upon a change in control of the Partnership, or its general partner, or managing general partner.

        A summary of the unit option activity for the period December 17, 2002 through December 31, 2002 is provided below:

 
  December 31, 2002
 
  Number of
units

  Weighted average
exercise price

Outstanding, beginning of period      
  Granted   175,000   $ 20.00
  Exercised      
  Forfeited      
Outstanding, end of period   175,000   $ 20.00
Options, exercisable at end of period        
Weighted average fair value of options granted       $ 1.15

        All options outstanding have an exercise price of $20.00 per unit and remaining contractual life of 10 years at December 31, 2002.

        The Partnership accounts for option grants in accordance with APB No. 25, Accounting for Stock Issued to Employees and follows the disclosure only provision of SFAS No. 123, Accounting for Stock-based Compensation.

        Crosstex Holdings has one stock-based compensation plan, the 2000 Stock Option Plan. Crosstex Holdings 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 plan. In accordance with APB No. 25, compensation is recorded to the extent the fair value of the stock exceeds the exercise price of the option at the measurement date. Compensation expense of $41,000, $0, and $0 was recognized in 2002, 2001, and 2000, respectively.

F-25


        A summary of the status of the 2000 Stock Option Plan as of December 31, 2002 and 2001, is presented in the table below:

 
  December 31, 2002
  December 31, 2001
 
  Shares
  Weighted
average
exercise price

  Shares
  Weighted
average
exercise price

Outstanding, beginning of period   340,500   $ 10.32   228,000   $ 10.00
  Granted   166,250     11.89   130,500     10.93
  Exercised            
  Forfeited   6,500     12.00   18,000     12.00
   
       
     
Outstanding, end of period   500,250     10.77   340,500     10.32
   
       
     
Options, exercisable at period end   288,503     10.38   76,000     10.00
Weighted average fair value of options granted         N/a         2.85
Fair value of $10 options granted         3.17         N/a
Fair value of $12 options granted         1.40         N/a
Fair value of $14 options granted         .91         N/a

        All options outstanding have an exercise price ranging from $10 to $14 at December 31, 2002.

        Crosstex Holdings modified certain terms of certain outstanding options in the first quarter of 2003. These modifications will result in variable award accounting for the modified options. Based on an assumed unit value of $23 per unit, total compensation expense would be approximately $2.2 million which will be recorded by Crosstex Energy, L.P. as non-cash stock based compensation expense in the first quarter of 2003. Compensation expense in future periods will be adjusted for changes in the unit market price and the remaining unvested portion.

        Basic earnings per unit was computed by dividing net income, by the weighted average number of limited partner units outstanding for the period December 17, 2002 through December 31, 2002. The computation of diluted earnings per unit further assumes the dilutive effect of unit options.

F-26


        The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the period December 17, 2002 through December 31, 2002 (in thousands, except per-unit amounts):

 
  December 17, 2002-
December 31, 2002

Basic earnings per unit:    
  Weighted average limited partner units outstanding   7,300
Dilutive earnings per unit:    
  Weighted average limited partner units outstanding   7,300
  Dilutive effect of exercise of options outstanding   10
   
Dilutive units   7,310

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

(9) Fair Value of Financial Instruments

        The estimated fair value of the Partnership's financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments.

 
  2002
  2001
 
  Carrying
Value

  Fair
Value

  Carrying
Value

  Fair
Value

Cash and cash equivalents   $ 1,308   1,308   352   352
Trade accounts receivable     104,802   104,802   58,222   58,222
Assets from energy risk management activities     3,102   3,102   3,478   3,478
Account receivable from Enron         2,467   2,467
Accounts payable and accrued gas purchases     110,793   110,793   56,092   56,092
Long-term debt     22,550   22,550   60,000   60,000
Liabilities from energy risk management activities     4,277   4,277   8,005   8,005

        The carrying amounts of the Partnership's cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

        The Partnership's long-term debt was comprised of borrowings under a revolving credit facility, which accrues interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value for the amounts outstanding under the credit facility.

        The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction.

F-27



(10) Risk Management and Financial Instruments

        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.

        Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2002 and 2001 (all quantities are expressed in British Thermal Units, and all prices are expressed in the Houston Ship Channel Inside FERC (HSC IF), Reliant East Inside FERC (Reliant IF), Panhandle Eastern Pipeline (PEPL) or Texas Eastern East Texas Inside FERC (TET Etx IF) for natural gas). The remaining term of the contracts extend no later than April 2004, with no single contract longer than 16 months. The Company's counterparties to hedging contracts include Williams and Sempra. As discussed in note 2, changes in the fair value of the Partnership's derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes in 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.

December 31, 2002

 
Transaction type

  Total
volume

  Pricing terms
  Remaining term
of contracts

  Fair value
 
Natural gas swaps
Cash flow hedge
  (500,000 ) 3.285 vs. Reliant IF to 4.01 vs. Reliant IF   January 2003-April 2004   $ (421,800 )
Natural gas swaps Cash flow hedge   (440,000 ) 3.415 vs. HSC IF to 4.99 vs HSC IF   January-September 2003     (573,320 )
Marketing trading transaction swaps   (1,149,000 ) 3.10 vs. TET Etx IF to 3.14 vs. TET Etx IF   January 2003-April 2004     (1,593,421 )
Marketing trading transaction swaps   (1,096,000 ) 3.21 vs. HSC IF to 5.16 vs. HSC IF   January-October 2003     (441,277 )
Marketing trading transaction swaps   (180,000 ) 3.185 vs Reliant IF to 3.635 vs. Reliant IF   January-May 2003     (219,330 )

F-28


December 31, 2001
 
Type transaction
  Total
volume

  Pricing terms
  Remaining term
of contracts

  Fair Value
 
Cash flow hedge swaps   (360,000 ) $2.905 vs. Reliant E IF to $3.1525 vs. Reliant E IF   January-December 2002   $ 122,880  
Cash flow hedge swaps   720,000   $2.60 vs. HSC IF to $5.96 vs HSC IF   January 2002     19,200  
Marketing trading transaction swap   (43,383 ) $2.625 vs. HSC IF to $5.715 vs. HSC IF   January 2002-December 2002     (1,649,247 )
Marketing trading transaction swaps   (1,147,500 ) $3.10 vs TET Etx to $3.14 TET Etx   January 2003-April 2004     (113,607 )

        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 Producer Services that are accounted for as energy trading contracts are included in assets and liabilities from risk management activities. Assets and liabilities related to Producer Services were as follows:

 
  December 31,
 
  2002
  2001
 
  (In thousands)

Assets from risk management activities:          
  Current   $ 2,947   3,196
  Long-term     155   117
Liabilities from risk management activities:          
  Current   $ 3,046   7,541
  Long-term     236   440

        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):

 
  Maturity periods
   
 
 
  Less than one year
  One to two years
  Two to three years
  Total fair value
 
December 31, 2002   $ (99 ) (81 )   (180 )
December 31, 2001     (4,345 ) (242 ) (81 ) (4,668 )

F-29


        The following reconciles the changes in fair value of energy trading contracts related to producer services activities from the beginning of each period to the end of the period.

 
  December 31,
 
 
  2002
  2001
  2000
 
 
  (In thousands)

 
Fair value of contracts at beginning of period   $ (4,668 ) 47    
Unrealized gains (losses)     4,488   (5,660 ) 47  
Unrealized gains (losses) attributable to changes in valuation techniques and assumptions          
Realized gains (losses) related to offsetting Enron contracts     (3,541 )      
Realized gains (losses) on settled contracts     1,756   1,946   1,206  
   
 
 
 
  Profit (loss) on Energy Trading Contracts     2,703   (3,714 ) 1,253  
Cash (received) paid on settled contracts     1,785   (1,946 ) (1,206 )
Purchase of financial contracts       945    
   
 
 
 
Fair value of contracts at end of period   $ (180 ) (4,668 ) 47  
   
 
 
 

Termination of Enron Positions

        On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (Enron), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Enron failed to make timely payment of approximately $3.9 million for physical deliveries of gas in 2001. This amount remained outstanding as of December 31, 2002. Additionally, the Partnership had entered into natural gas hedging and physical delivery contracts with Enron. According to the terms of the contracts, Enron is liable to the Partnership for the mark-to-market value of all contracts outstanding on the date the Partnership exercised its termination right under the contracts, which totaled approximately $4.6 million and which was recorded as a receivable from Enron. The Partnership has accounted for these contracts as energy trading contracts whereby changes in fair value of the fixed price purchase and sales commitments are recognized in earnings.

        The Partnership had offsets to the above amounts totaling approximately $0.3 million, resulting in a net amount of $8.2 million receivable from Enron at December 31, 2001. Due to the uncertainty of future collections, a charge and related allowance for 70% of the net receivable, or $5.7 million, was recorded at December 31, 2001. The 30% recovery rate was management's best estimate based on current market transactions. Due to the uncertainty of the timing of recovery of this receivable due to Enron's bankruptcy the Partnership classified this receivable as long-term at December 31, 2001. No balance is reflected at December 31, 2002 as the receivable was transferred to Crosstex Holdings in conjunction with the initial public offering.

        For the year ended December 31, 2001, the Partnership recorded a loss on energy trading contracts related to natural gas marketing of $5.7 million, substantially all of which related to estimated

F-30



losses on claims from Enron. This loss was partially offset by gains of $1.9 million on energy trading contracts which physically settled during 2001.

        The Partnership had fixed price sales commitments to Enron which offset fixed price purchase commitments from producers. Due to Enron's bankruptcy, the Partnership was exposed to future natural gas price movements related to the fixed price purchase commitments. The Partnership entered into new fixed price sales commitments with a new counterparty for a portion of the volume, and purchased or sold exchange-traded natural gas option contracts to mitigate the effects of future price declines. The change in fair value of these sales contracts and options is recorded in earnings as profit or loss on energy trading contracts.

        Option contracts outstanding related to the fixed price purchase commitments at December 31, 2001 were as follows:

December 31, 2001
Transaction type
  Total
volume

  Pricing terms
  Remaining term
of contracts

  Fair value
Purchased Puts   3,840,000   $2.50 vs. NYMEX Natural Gas to $2.70 vs. NYMEX Natural Gas   February-October 2002   $ 1,184,600

        The Enron receivable was distributed to Crosstex Holdings prior to the initial public offering of Crosstex Energy, L.P.

(11) 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 by Yorktown in Camden. During the years ended December 31, 2002 and 2001 and the eight months ended December 31, 2000, the Partnership purchased natural gas from Camden in the amount of approximately $10,076,000, $17,300,000, and $2,645,000, respectively, and received approximately $399,000, $737,000, and $53,000 in treating fees from Camden.

        Subsequent to April 30, 2000, the Partnership had related-party transactions with Crosstex Pipeline Company (CPC), and prior to that date, the Partnership had related-party transactions with Crosstex Energy, Inc. (CEI), CPC, Vantex Energy Services (VES), Texas Energy Transfer Company (TETC), and Energy Transfer Company (ETC), all of which are summarized below:

F-31


(12) Commitments and Contingencies

        Leased office space and equipment have remaining noncancelable lease terms in excess of one year. The following table summarizes our remaining noncancelable future payments under operating leases as of December 31, 2002:

2003   $ 841,942
2004     751,288
2005     567,558
2006     71,971
2007    
Thereafter    

        Operating lease rental expense in the years ended December 31, 2002 and 2001, the eight months ended December 31, 2000, and the four months ended April 30, 2000, was approximately $951,000, $1,200,000, $608,000, and $200,000, respectively.

F-32



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

        The Partnership has an agreement with a consulting firm which helped facilitate certain acquisitions for the Partnership. In addition to the regular fee received for their services, the consulting firm also entered into an agreement with the Partnership by which they would receive a 10% net profit interest from the acquired assets after the acquisitions have reached payout, which includes a 10% rate of return. The assets subject to the net profits interest generated approximately $3,224,000 in cash flow during 2001. In December 2002, the Partnership acquired the interest for $684,000. The acquisition of the net profits interest has been accounted for as a cost of the related acquired assets.

(13) 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 Gulf Coast System, the Corpus Christi System, the Gregory gathering system located around the Corpus Christi area, the Arkoma system in Okalahoma and various other small systems. Also included in the Midstream division are the Partnership's Producer Services operations (note 2(h)). 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.

        The accounting polices of the operating segments are the same as those described in note 2 of the Notes to Consolidated Financial Statements. The Partnership evaluates the performance of its operating segments based on earnings before income taxes and accounting changes, and after an allocation of corporate expenses. Corporate expenses are allocated to the segments on a pro rata basis based on assets. Intersegment sales are at cost.

F-33



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

 
  Midstream
  Treating
  Totals
 
 
  (in thousands)

 
Year ended December 31, 2002:                
  Sales to external customers   $ 437,676   14,817   452,493  
  Intersegment sales     4,073   (4,073 )  
  Interest expense     (2,327 ) (390 ) (2,717 )
  Depreciation and amortization     5,738   2,007   7,745  
  Segment profit (loss)     3,271   (1,269 ) 2,002  
  Segment assets     199,056   33,382   232,438  
  Capital expenditures     11,154   3,391   14,545  

Year ended December 31, 2001:

 

 

 

 

 

 

 

 
  Sales to external customers   $ 362,673   24,353   387,026  
  Intersegment sales     10,633   (10,633 )  
  Interest expense     1,840   413   2,253  
  Depreciation and amortization     4,534   1,567   6,101  
  Segment profit (loss)     (4,607 ) 689   (3,918 )
  Segment assets     137,303   31,073   168,376  
  Capital expenditures     6,484   16,201   22,685  

Eight months ended December 31, 2000:

 

 

 

 

 

 

 

 
  Sales to external customers   $ 88,008   17,392   105,400  
  Intersegment sales     13,127   (13,127 )  
  Interest expense     477   53   530  
  Depreciation and amortization     1,433   828   2,261  
  Segment profit     1,302   321   1,623  
  Segment assets     181,297   19,971   201,268  
  Capital expenditures     2,519   2,148   4,667  

Four months ended April 30, 2000:

 

 

 

 

 

 

 

 
  Sales to external customers   $ 3,591   5,947   9,538  
  Intersegment sales     4,883   (4,883 )  
  Interest expense     57   22   79  
  Depreciation and amortization     243   279   522  
  Segment profit (loss)     (8,132 ) 455   (7,677 )
  Segment assets     26,298   10,104   36,402  
  Capital expenditures       3,026   3,026  

F-34


(14) Quarterly Financial Data (Unaudited)

        Summarized unaudited quarterly financial data is presented below.

 
  First
  Second
  Third
  Fourth
  Total
 
2001:(3)                        
  Revenues   $ 81,725   123,942   83,913   97,446   387,026  
  Operating income     2,901   3,254   4,906   5,702   16,763  
  Net income (loss)     1,719   144   784   (6,565) (1) (3,918 )

2002:(3)

 

 

 

 

 

 

 

 

 

 

 

 
  Revenues   $ 80,993   126,480   114,611   130,409   452,493  
  Operating income     4,681   5,468   6,182   5,945   22,276  
  Net income (loss)     (252) (2) 224   1,485   545 (2) 2,002  

(1)
Included in the 2001 fourth quarter results is a charge of $5.8 million related to Enron write-offs as discussed in footnote (10), and an impairment of $2.9 million related to the impairment of certain intangible assets associated with an asset no longer owned by the Partnership.
(2)
Included in the 2002 first and fourth quarter results are impairment charges of $3.2 million and $1.0 million, respectively, principally related to the impairment of certain intangibles related to gas plants.
(3)
The Company stopped amortizing goodwill effective January 1, 2002 with the adoption of SFAS No. 142. See Note 2(n).

F-35



Schedule II

CROSSTEX ENERGY, L.P.
(Successor to Crosstex Energy Services, Ltd.)

(In thousands)

 
  Balance at
beginning
of period

  Charged to
costs and
expenses

  Deductions
  Balance at
end of
period

Year ended December 31, 2002                  
  Allowance for doubtful accounts   $ 5,776     (5,776 )(a)

Year ended December 31, 2001

 

 

 

 

 

 

 

 

 
  Allowance for doubtful accounts   $   5,776     5,776

Eight months ended December 31, 2000

 

 

 

 

 

 

 

 

 
  Allowance for doubtful accounts   $      

Four months ended April 30, 2000 (Predecessor)

 

 

 

 

 

 

 

 

 
  Allowance for doubtful accounts   $      

(a)
The Enron receivable was contributed to Crosstex Holdings at the time of the initial public offering and therefore the related allowance is no longer recorded on the books of the Partnership.

S-1