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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K

Commission file number: 000-50536

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

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

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

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

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

        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

        There were no Common shares held by non-affiliates of the registrant on June 30, 2003.

        At February 28, 2004, there were outstanding 12,079,248 Common shares.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

DESCRIPTION

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CROSSTEX ENERGY, INC.

PART I

Item 1. Business

General

        Crosstex Energy, Inc. is a Delaware corporation, formed in April 2000. We completed our initial public offering in January 2004. Our shares of common stock are listed on the NASDAQ National Market under the symbol "XTXI". 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 "Crosstex Energy, Inc." as well as the terms "our," "we," and "us," or like terms are sometimes used as references to Crosstex Energy, Inc. and its consolidated subsidiaries. References in this report to "Crosstex Energy, L.P.," the "Partnership," or like terms refer to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. and its consolidated subsidiaries.

CROSSTEX ENERGY, INC.

        Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas. These partnership interests consist of the following:

•

333,000 common units and 4,667,000 subordinated units, representing a 54.3% limited partner interest in the Partnership; and



•

100% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

        Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership's business or to provide for future distributions.

        The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.50 for that quarter, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter.

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        The following table sets forth the distributions we received from the Partnership since its initial public offering in December 2002.

(1)

Reflects the pro rata minimum quarterly distribution covering the period from the closing of the Partnership's initial public offering on December 17, 2002 through December 31, 2002. This distribution was paid to us together with the March 31, 2003 distribution.

        We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

•

federal income taxes, which we are required to pay because we are taxed as a corporation;



•

the expenses of being a public company;



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other general and administrative expenses;



•

capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner's 2.0% general partner interest; and



•

reserves our board of directors believes prudent to maintain, including reserves equal to the benefit we will receive in 2004 from our existing net operating loss carryforwards.

        If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions.

        Our ability to pay dividends is limited by the Delaware General Corporation Law, which provides that a corporation may only pay dividends out of existing "surplus," which is defined as the amount by which a corporation's net assets exceeds its stated capital. While our ownership of the general partner and the common and subordinated units of the Partnership are included in our calculation of net assets, the value of these assets may decline to a level where we have no "surplus," thus prohibiting us from paying dividends under Delaware law.

        The Partnership's 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 its assets by increasing their utilization while controlling costs and pursuing new construction or expansion opportunities in its core operating areas. If the Partnership is successful in implementing this strategy, we believe the total amount of cash distributions it makes

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will increase and our share of those distributions will also increase. The Partnership announced increases in its quarterly distribution two times since its initial public offering in December 2002. During that time, the Partnership increased the per unit quarterly cash distribution on its common and subordinated units by 40.0%, from $0.50 to $0.70. If the Partnership increased its per unit quarterly distribution to $0.80, its total quarterly distribution would increase $1,504,167 and we would receive $1,101,667, or 73.2%, of that increase. If Crosstex Energy, L.P. then issued an additional 1,000,000 units and maintained its per unit quarterly distribution at $0.80 per unit, its total quarterly distribution would increase another $923,930 and we would receive $123,930, or 13.4%, of that increase, assuming the general partner made a capital contribution to the Partnership sufficient to maintain its 2.0% general partner interest.

        So long as we own the general partner, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of a majority of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. The Partnership may elect to forego an opportunity for several reasons, including:

•

the nature of some or all of the target's assets or income might affect the Partnership's ability to be taxed as a partnership for federal income tax purposes;



•

the board of directors of Crosstex Energy GP, LLC may conclude that some or all of the target assets are not a good strategic opportunity for the Partnership; or



•

the seller may desire equity, rather than cash, as consideration and may not want to accept the Partnership's units as consideration.

        We have no present intention of engaging in additional operations or pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement, although we may decide to pursue them in the future, either alone or in combination with the Partnership. In the event that we pursue the types of opportunities that we are permitted to pursue under the omnibus agreement, our board of directors, in its sole discretion, may retain all, or a portion of, the cash distributions we receive on our partnership interests in the Partnership to finance all, or a portion of, such transactions, which may reduce or eliminate dividends paid to our stockholders.

CROSSTEX ENERGY, L.P.

        Crosstex Energy L.P. is a rapidly growing independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas. The Partnership connects the wells of natural gas producers in its market areas to its gathering systems, 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. The Partnership purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generates gross margins based on the difference between the purchase and resale prices. In addition, the Partnership purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.

        The Partnership's major assets include over 2,500 miles of natural gas gathering and intrastate transmission pipelines, three natural gas processing plants connected to its gathering systems with a total NGL production capacity of 289,800 gallons per day and 61 natural gas treating plants. The Partnership's recently announced acquisition of LIG Pipeline Company (LIG) will add 2,000 miles of

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pipeline and three major processing plants to the Partnership's assets. The Partnership's 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. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership's processing plants remove NGLs from a natural gas stream and fractionate, or separate, the NGLs into separate NGL products, including ethane, propane, mixed butanes and natural gasoline. The Partnership's 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.

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

(1)

Certain Gulf Coast customers are now provided service through the Vanderbilt system.

(2)

Represents average throughput from the acquisition date, June 30, 2003, through December 31, 2003.

        The Partnership has two operating segments, Midstream and Treating. The Partnership's Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while its Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. See Note 15 to the consolidated financial statements for financial information about these operating segments.

        The Partnership's 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

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Energy GP, L.P.'s general partner. Crosstex Energy GP, LLC manages the Partnership's operations and activities and employs the Partnership's officers.

        References in this report to "Crosstex Energy, L.P.'s predecessor" or the "Partnership's 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 its initial public offering in December 2002.

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

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

Business Strategy

        The Partnership's 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 its 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. The Partnership's strategy is based on its expectation of a continued high level of drilling in its principal geographic areas and a process of ongoing divestitures of gas transportation and processing assets by large industry participants. The Partnership believes these two factors should present opportunities for continued expansion in its 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 the Partnership's strategy include the following:

•

Pursuing accretive acquisitions.    The Partnership intends to use its acquisition and integration experience to continue to make strategic acquisitions of midstream assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset. The Partnership pursues acquisitions that it believes will add to existing core areas in order to capitalize on its existing infrastructure, personnel, and producer and consumer relationships. The Partnership also examines opportunities to establish new core areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. The Partnership plans to establish new core areas primarily through the acquisition of key assets that will serve as a platform for further growth both through additional acquisitions and the construction of new assets. A recent example of establishing a new core area includes the Mississippi pipeline system acquired as part of the DEFS acquisition. This system provides the Partnership with a platform to develop a significant presence in the south central Mississippi area.



•

Improving existing system profitability.    After the Partnership acquires or constructs a new system, it begins an aggressive effort to market services directly to both producers and end users in order to connect new supplies of natural gas, improve margins, and fully utilize the system's capacity. Many of the Partnership's recently acquired systems have excess capacity that provides it opportunities to increase throughput with minimal incremental cost. As part of this process, the Partnership focuses on providing a full range of services to small and medium size independent producers and end users, including supply aggregation, transportation and hedging, which the Partnership believes provides it with a competitive

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advantage when it competes for sources of natural gas supply. Additionally, the Partnership emphasizes increasing the percentage of our natural gas sales directly to end users, such as industrial and utility consumers in an effort to increase our operating margins. For the year ended December 31, 2003, approximately 58% of the Partnership's on-system natural gas sales were to industrial end users and utilities.

•

Undertaking construction and expansion opportunities.    The Partnership leverages its existing infrastructure and producer and customer relationships by constructing and expanding systems to meet new or increased demand for its gathering, transmission, treating, processing and marketing services. These projects include expansion of existing systems and construction of new facilities. The Partnership's 2002 acquisition of the Hallmark Lateral facilitated the establishment of connections between its Corpus Christi and its Gulf Coast systems which has increased its flexibility in balancing gas supply and market requirements throughout the regions covered. In August 2003, the Partnership expanded the capacity of its Gregory processing plant from 99,900 MMBtu/d to 166,500 MMBtu/d, a 67% increase over its previous capacity, and began marketing the additional gas through its Corpus Christi and Gulf Coast systems. The Partnership further enhanced the Gregory system by acquiring the Koch Ingleside Pipeline and connecting directly to a major end user customer.

Recent Acquisitions and Expansion

        Duke Energy Field Services.    In June 2003, the Partnership acquired various midstream assets located in Mississippi, Texas, Alabama and Louisiana from DEFS for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. The acquisition provided the Partnership with a new core area for growth in south central Mississippi, expanded its presence in West Texas, increased the total miles of its pipelines from 1,700 to 2,500 and enabled it to enter the business of carbon dioxide separation. In addition, the Partnership believes that the acquisition has increased the stability of its cash flow as operating profits from the Mississippi pipeline system are generated through purchasing, gathering, transporting and reselling natural gas which generates margins not affected by commodity prices, and a majority of the income it receives from the Seminole gas plant is based on fixed fees for carbon dioxide separation and sulfur removal.

        Gregory Expansion.    In August 2003, the Partnership completed an expansion of its Gregory processing plant. The expansion increased the plant capacity from approximately 99,900 MMBtu/d to 166,500 MMBtu/d, at a cost of approximately $7.0 million. In addition, the Partnership has significantly reduced its exposure to commodity prices by renegotiating a number of its commodity based contracts, where revenues were subject to fluctuating commodity prices, to fee-based contracts.

        Subsequent Event.    The Partnership entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power for $76.2 million. The acquisition will increase the Partnership's pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. The Partnership will finance the acquisition through borrowings under our existing bank credit facility, issuance of additional senior notes or other financing alternatives.

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Other Developments

        Partnership's Follow-on Offering.    In September 2003, the Partnership completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. The Partnership received net proceeds of approximately $59.1 million, including an approximate $1.3 million capital contribution by the general partner. The net proceeds were used to repay borrowings outstanding under the bank credit facility of its operating partnership.

        Bank Credit Facility.    In June 2003, the Partnership's operating partnership, Crosstex Energy Services, L.P., entered into a new $100.0 million senior secured credit facility, which was increased to $120 million in October 2003, consisting of a $70.0 million acquisition facility and a $50.0 million working capital and letter of credit facility. As of December 31, 2003, the operating partnership had $20.0 million of outstanding borrowings under the acquisition facility and $30.3 million of letters of credit issued under the working capital and letter of credit facility. The credit facility matures in June 2006.

        Secured Secured Notes.    In June 2003, the operating partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, the operating partnership issued $10.0 million of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years. The senior secured notes are guaranteed by the operating partnership's subsidiaries and us. The operating partnership used the net proceeds from the senior notes offering to repay indebtedness under its bank credit facility.

Midstream Division

        Gathering and Transmission.    The Partnership's primary Midstream assets include systems located primarily along the Texas Gulf Coast and in south-central Mississippi, which, in the aggregate, consist of approximately 2,500 miles of pipeline and three processing plants and contributed approximately 78% and 72% of our gross profit in 2003 and 2002, respectively.

•

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. The Partnership 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 80 receipt points and five treating and processing plants operated by third parties. This system has three delivery laterals 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 the Partnership may purchase volumes not gathered through its systems for resale or through which it might deliver natural gas to customers which are not connected to its system. The Partnership transports gas on the TXU Lone Star pipeline providing access for its 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 has a capacity of 210,600 MMBtu/d and average throughput on this system was approximately 85,000 MMBtu/d for the year ended December 31, 2003.

The Partnership generates operating profits in its Gulf Coast system through the margins it earns by purchasing, gathering, transporting and reselling natural gas. The Partnership

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purchases natural gas from a producer, pipeline or marketing company and then transport and resells the gas. As of December 31, 2003, the Partnership was purchasing gas from over 70 producers primarily pursuant to month-to-month contracts and was reselling the natural gas to approximately 10 customers primarily pursuant to short-term or month-to-month arrangements. For the year ended December 31, 2003, approximately 92% of the natural gas volumes it purchased was purchased at a fixed price relative to an index and the remainder was purchased at a percentage of an index, and all the natural gas volumes it sold was sold at a fixed price relative to an index.

•

Vanderbilt System.    The Partnership's Vanderbilt system consists of approximately 200 miles of gathering and transmission pipelines located in Wharton and Fort Bend Counties near its Gulf Coast system. Natural gas is supplied to the system from over 27 receipt points. The gas had been sold to the Exxon Katy plant and, in June 2003, the Partnership reversed the flow of gas and began deliveries to the Formosa Hydrocarbons processing plant at Point Comfort, Texas. The Partnership's Vanderbilt system has a capacity of 141,700 MMBtu/d and average throughput was approximately 49,000 MMBtu/d for the year ended December 31, 2003. The Partnership acquired the Vanderbilt system in December 2002 for a purchase price of $12.0 million.

All the gas in the Vanderbilt system is now sold to Formosa Hydrocarbons under a ten year agreement which began in June 2003 to supply up to 60,000 MMBtu/d. The gas is sold to Formosa at a fixed price relative to an index. Gas is purchased from approximately 15 producers, primarily pursuant to month-to-month arrangements, at over 25 receipt points. Approximately 55% percent of the gas is purchased at a percentage of an index, and the remainder is purchased at a fixed price relative to an index. The Partnership generates operating profits in the system through the margins it earns by purchasing gas from producers, then gathering, transporting and reselling the natural gas to Formosa.

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Corpus Christi System.    The Corpus Christi system is an intrastate pipeline system consisting of approximately 295 miles of gathering and transmission pipelines and extending from supply points in south Texas to markets in the Corpus Christi area. The Partnership's gathering and transmission pipelines range in diameter from four to 20 inches. The Partnership acquired the Corpus Christi system in May 2001 in conjunction with the acquisition of the Gregory gathering system and Gregory processing plant, which it collectively refers to as the CCNG Acquisition, for an aggregate purchase price of approximately $30 million. The Partnership's Corpus Christi system had average throughput of approximately 152,000 MMBtu of gas per day at the time of its acquisition. The main lines comprising the Corpus Christi system were constructed at various times from the 1940's through the 1990's.

Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 16 treating and processing plants and third party gathering systems and pipelines. The system interconnects with multiple third party pipelines through which the Partnership purchases volumes not gathered through its systems for resale and delivers natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system has a capacity of 355,950 MMBtu/d and average throughput on this system was approximately 213,800 MMBtu/d for the year ended December 31, 2003.

In June 2002, the Partnership acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows it to access new markets within Texas and to interconnect to the Florida Gas system within Texas. The Partnership has constructed an addition to this transmission line creating a connection between its Gulf Coast system and its Corpus Christi system. This connection allows the Partnership to transport gas between our

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two systems, thereby reducing our dependence on third-party suppliers, move gas supplies to more favorable markets and enhance our margins. In November 2002, the Partnership completed construction of the interconnect between the Hallmark Lateral and the Florida Gas system. With this connection, the Partnership began selling gas into the Florida markets and sold approximately 57,000 MMBtu/d for the year ended December 31, 2003.

The Partnership generates operating profits in its Corpus Christi system through the margins it earns by purchasing, gathering, transporting and reselling natural gas. As of December 31, 2003, the Partnership was purchasing natural gas from approximately 35 producers generally on month-to-month or short-term arrangements. For the year ended December 31, 2003, substantially all of the natural gas volumes the Partnership purchased were purchased at a fixed price relative to an index. The Corpus Christi system transports natural gas to the Corpus Christi area where the Partnership's customers include multiple major refineries and other industrial installations, as well as the local electric utility. As of December 31, 2003, the Partnership was selling gas to over 20 customers primarily pursuant to contracts that expire at various times between 2003 and 2006. For the year ended December 31, 2003, all of the natural gas volumes the Partnership sold were sold at a fixed price relative to an index.

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Gregory Gathering System.    The Partnership acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the acquisition of the Corpus Christi system. 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 two inches to 18 inches with a total estimated throughput capacity of 222,000 MMBtu/d. The gathering system had average throughput of approximately 151,000 MMBtu/d for the year ended December 31, 2003 compared to an average throughput of approximately 76,500 MMBtu/d of gas per day at the time of its acquisition. The Gregory Gathering System was constructed in the 1980s.

The Partnership generates operating profits in its Gregory gathering system through the margins earned by purchasing, gathering, transporting and reselling natural gas. As of December 31, 2003, the Partnership was purchasing gas from over 60 producers primarily pursuant to month-to-month contracts, and for the year ended December 31, 2003, approximately 95% of the natural gas volumes it purchased were purchased at a fixed price relative to an index and the remainder was purchased at percentage of an index.

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Gregory Processing Plant.    The Partnership's 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. The Partnership's Gregory processing plant inlet capacity was expanded from 99,900 MMBtu/d to approximately 166,500 MMBtu/d during 2003, and average throughput was approximately 106,000 MMBtu/d for the year ended December 31, 2003. At the time of acquisition, the plant was processing approximately 43,400 MMBtu/d of gas per day. The Gregory processing plant was constructed in the 1980s and expanded and upgraded in 1998 and 2003.

In addition to the margins generated by the Gregory gathering system, the Partnership generates revenues at its Gregory processing plant under two types of arrangements:

•

For the year ended December 31, 2003, the Partnership purchased approximately 16% of the natural gas volumes on its Gregory system under contracts in which it was exposed to the risk of loss or gain in processing the natural gas. Under these contracts, the

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Partnership fractionates the NGLs into separate NGL products, which it then sells at prices based upon the market price for NGL products. The processed natural gas is delivered to multiple customers at prices based on a fixed price relative to a monthly index. Since the Partnership extracts Btus from the gas stream in the form of the liquids or consumes it as fuel during processing, the Partnership reduces the Btu content of the natural gas but seek to more than offset this by creating value from the separated NGL products. Accordingly, the Partnership's margins under these arrangements can be negatively affected in periods where the value of natural gas is high relative to the value of NGLs.

•

For the year ended December 31, 2003, the Partnership purchased approximately 84% of the natural gas volumes on its Gregory system at a spot or market price less a discount that includes a conditioning fee for processing and marketing the natural gas and NGLs at its Gregory processing plant with no risk of loss or gain in processing the natural gas. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas.



•

Arkoma Gathering System.    The Partnership 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, the Partnership has 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 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 170 wells to three compressor stations for discharge to a mainline transmission pipeline. This system has a capacity of 21,400 MMBtu/d and average throughput was approximately 13,000 MMBtu/d for the year ended December 31, 2003.

The Partnership generates a margin for gathering and transporting gas in the Arkoma gathering system equal to a percentage of the proceeds from the sale of the natural gas to the mainline transmission pipeline into which it delivers. The Partnership takes title to the gas at the point of receipt into the gathering system, with payment based upon an allocation of the metered volume sold into the mainline transmission facilities of our customer with the producer sharing their pro rata portion of the fuel costs for the compression and the removal of water from the natural gas stream.

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Mississippi Pipeline System.    The Partnership acquired the Mississippi pipeline system from DEFS in June 2003 in connection with the DEFS acquisition. The Mississippi pipeline system is located in 15 counties of south Mississippi spanning from the city of Jackson in the northwest to Hattiesburg in the southeast. The system has wellhead supply connections in most of the gas fields in the counties of operation—primarily Jasper, Jefferson Davis, Lawrence, Marion and Simpson counties. The system delivers natural gas through direct market connections to utilities and industrial end users. The pipeline system consists of approximately 638 miles of pipeline ranging in diameter from four to 20 inches with a total estimated capacity of 198,500 MMBtu/d. Average throughput on this system was approximately 79,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970s.

The Partnership generates operating profits in our Mississippi pipeline system by purchasing, gathering, transporting and reselling natural gas. The Partnership purchases gas from

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approximately 50 producers at the delivery points into the system and gas is sold to approximately 15 customers. The majority of contracts provide that natural gas volumes are purchased at a fixed price relative to an index.

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Seminole Gas Processing Plant.    The Partnership owns an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas. The Seminole plant has dedicated long-term reserves from the Seminole San Andres unit, to which it also supplies carbon dioxide under a long-term arrangement. Revenues at the plant are derived from a fee it charges producers, including those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.59 for each Mcf of carbon dioxide returned. The plant also receives 50% of the NGLs produced by the plant. The Partnership has entered into a one-year contract with Duke Energy NGL Services, L.P. to market its NGLs on its behalf. The Partnership receives its share of proceeds from the sale of carbon dioxide from the plant operator. The Partnership is separately billed by the plant operator for its share of expenses. The plant had capacity of 150,000 Mcf/d at the time of acquisition. The recently completed expansion increased capacity by 60,000 Mcf/d, increasing total capacity to 210,000 Mcf/d. Average throughput for the plant was approximately 144,000 Mcf/d for the last six months of 2003. The plant was constructed in the 1980s.



•

Conroe Gas Plant And Gathering System.    The Partnership acquired the Conroe gas plant and gathering system in June 2003 in connection with the DEFS asset acquisition. Located in Montgomery County, Texas, the Conroe gas plant is a cryogenic gas processing plant with 10 miles of gathering pipelines located within the Conroe Field Unit, which is operated by ExxonMobil. The plant gathers low pressure and high pressure natural gas through contracts with over 20 producers. The plant has outlet natural gas connections to Kinder Morgan Texas Pipeline, L.P. and Copano Field Services. Recovered NGLs are delivered into the Chaparral NGL pipeline. The plant has a capacity of 70,265 MMBtu/d and average throughput on this system was approximately 26,000 MMBtu/d for the year ended December 31, 2003. The Conroe gas plant was constructed in the 1930s.

The Partnership generates operating profits at our Conroe gas plant from one customer primarily from compression and processing fees and from retaining 40% of the NGLs from the recycled lift gas.

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Alabama Pipeline System.    The Partnership acquired the Alabama pipeline system in June 2003 in connection with the DEFS asset acquisition. The system is located in Fayette, Lamar, Picken and Tuscaloosa Counties in west-central Alabama. The system gathers coalbed methane gas from the Black Warrior Basin and other conventional wells. The system is a series of three natural gas gathering and transmission systems consisting of approximately 125 miles of four to twelve inch pipeline with an estimated capacity of 72,300 MMBtu/d. One supplier to the system accounted for over half of the gas gathered. The gas is delivered primarily to industrial end users. Average throughput on this system was approximately 14,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970's.

The Partnership generates operating profits in its Alabama pipeline system by gathering, transporting and reselling natural gas. All gas is purchased at the delivery points into the system. The majority of the contracts are priced at a fixed basis to an area index and the Partnership sells gas to approximately five customers.

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Other Systems.    The Partnership owns several small gathering systems totaling approximately 135 miles, including the Manziel system in Wood County, Texas, the San Augustine system in

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San Augustine County, Texas, the Freestone Rusk system in Freestone County, Texas, the Jack Starr and North Edna systems in Jackson County, Texas and the Cadeville and Aurora Centana systems in Louisiana. Through Crosstex Pipeline Partners, a limited partnership of which the Partnership is the co-general partner, the Partnership owns a 28% interest in five gathering systems in east Texas, totaling 64 miles with a combined capacity of 119,000 MMBtu/d. The Partnership also owns 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 4,200 MMBtu/d for the year ended December 31, 2003. In addition to these systems, the Partnership owns various smaller gathering and transmission systems located in Texas, New Mexico and Louisiana.

        Producer Services.    The Partnerhip currently purchases for resale volumes of natural gas that do not move through its gathering, processing or transmission assets from over 50 independent producers. The Partnership engages in such activities on more than 20 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. The Partnership focuses on supply aggregation transactions in which it either purchases and resells gas and thereby eliminates 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. Profits from energy trading activities for the year ended December 31, 2003 and 2002 were $1.9 million and $2.7 million, respectively.

        The Partnership's business strategy includes developing relationships with natural gas producers to facilitate the purchase of its production on a long-term basis. The Partnership believes that this business also provides it with strategic insights and valuable market intelligence which may impact its expansion and acquisition strategy.

        The Partnership offers to its customers the ability to hedge their purchase or sale price by agreeing to sell to it or to purchase from it volumes of natural gas. This risk management tool enables its customers to reduce pricing volatility associated with the sale and purchase of natural gas. When the Partnership agrees to purchase or sell natural gas from a customer, it contemporaneously executes a contract for the sale or purchase of such natural gas or the Partnerhip enters into an offsetting obligation using futures contracts on the New York Mercantile Exchange or by using over-the-counter derivative instruments with third parties.

Treating Division

        The Partnership operates 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 Partnership's treating division contributed approximately 22% and 27% of our gross margin in 2003 and 2002, respectively. The Partnership's treating business has grown from 35 plants in operation at December 31, 2002 to 52 plants in operation at December 31, 2003.

        As of December 31, 2003, the Partnership owned 61 treating plants, 41 of which were operated by its personnel, 11 of which were operated by producers, and 9 of which were held in inventory. The Partnership entered the treating business in 1998 with the acquisition of WRA Gas Services and it is now one of the largest gas treating operations in the Texas Gulf Coast. 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, as well as other locations, is high in carbon dioxide. The majority of the Partnership's active plants are treating gas from the Wilcox and Edwards formations in the Texas Gulf Coast, both of which are deeper formations that are high in carbon dioxide. The

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Partnership's active treating facilities include 47 amine plants and five hydrogen sulfide scavenger installations. In cases where producers pay the Partnership to operate the treating facilities, the Partnership either charges a fixed rate per Mcf of natural gas treated or charges a fixed monthly fee.

        In addition to the Partnership's treating plants, it has three gathering systems 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 the Partnership's treating plants. The diameter of these gathering pipelines ranges from two to six inches. These gathering assets in the aggregate have a capacity of 61,000 MMBtu/d and average throughput was approximately 20,800 MMBtu/d for the year ended December 31, 2003. In cases where the Partnership both gathers and treats natural gas, its fee is generally based on throughput.

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

        Treating process.    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. The size range of the 52 plants in operation is 3.5 to 300 gallons per minute, and the size range of the 9 plants in inventory is 3.5 to 1,000 gallons per minute.

        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. The facilities are primarily vertical towers mounted on concrete foundations. As of December 31, 2003, the Partnership had two such facilities which were operated by the producer.

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Industry Overview

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

        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, 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. Most natural gas produced by a well 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 moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream, as well as the removal of contaminants. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.

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        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. All of our transmission pipelines are intrastate systems.

Risk Management

        As the Partnership purchases natural gas, it establishes a margin by selling natural gas for physical delivery to third party users, using over-the-counter derivative instruments or by entering into a future delivery obligation under futures contracts on the New York Mercantile Exchange. Through these transactions, the Partnership seeks to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. The Partnership's policy is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes.

Competition

        The business of providing natural gas gathering, transmission, treating, processing and marketing services is highly competitive. The Partnership faces strong competition in acquiring new natural gas supplies. The Partnership's 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. The main difference between the Partnership and its competitors is that the Partnership offers most midstream services, while its competitors typically offer only a few select services. Many of its competitors have substantially greater capital resources and control substantially greater supplies of natural gas. The Partnership's 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. The Partnership's major competitors in Mississippi for natural gas supplies and markets include Southern Natural Gas and Gulf South Pipeline Company.

        The Partnership's gas treating operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant and operations similar to ours. The Partnership also faces competition from vendors of used equipment that occasionally operate plants for producers. The Partnership's primary competitor for natural gas treating services in our principal market area is The Hanover Company.

        In marketing natural gas, the Partnership has 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 its marketing operations.

Natural Gas Supply

        The Partnership's end-user pipelines have connections with major interstate and intrastate pipelines, which the Partnership believes have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of the Partnership's gathering systems, it evaluated well and reservoir data furnished by producers to determine the availability of natural gas supply for the systems. Based on those evaluations, the Partnership believes that there should be adequate natural gas supply to recoup its investment with an adequate rate of return. The Partnership does not routinely obtain independent evaluations of reserves

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dedicated to its systems due to the cost of such evaluations. Accordingly, the Partnership does not have estimates of total reserves dedicated to its systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

        The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the Partnership's purchase and resale of gas exposes it 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 the Partnership's overall profitability.

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

Regulation

        Regulation by FERC of Interstate Natural Gas Pipelines.    Under the Natural Gas Act ("NGA"), the Federal Energy Regulatory Commission ("FERC") generally regulates the transportation of natural gas in interstate commerce. The Partnership does not own any interstate natural gas pipelines, so FERC does not directly regulate any of its facilities or operations. However, as discussed below, the Partnership does perform some interstate transmission service that is incidental to its intrastate business, and this interstate transmission is subject to FERC rate regulation. Also, FERC's regulation of interstate transportation by others indirectly influences certain aspects of the Partnership's business and the market for its products. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines' rates and rules and policies that may affect rights of access to natural gas transportation capacity.

        Intrastate Pipeline Regulation.    The Partnership's intrastate natural gas pipeline operations are not subject to 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, or TRRC. However, to the extent that the Partnership's intrastate pipeline systems provide incidental transportation of natural gas in interstate commerce, the rates, terms and conditions of such transportation services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act ("NGPA"). Section 311 applies to, among other things, the providing 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. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.

        The Partnership's 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 the Partnership charges for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. The Partnership cannot predict whether such a complaint will be filed against it or whether the TRRC will change its regulation of these rates.

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        A twelve-mile section of the Partnership's Mississippi gathering system is regulated by the Mississippi Oil and Gas Board as it transports gas not owned by the Partnership for a fee. The Partnership's one hundred twenty-five mile gathering system in Oklahoma is not regulated by the Oklahoma Corporation Commission. Similarly, gathering systems the Partnership owns in Alabama and Louisiana are not subject to regulation by the Alabama State Oil and Gas Board and the Louisiana Office of Conservation respectively. While it is possible that Alabama, Louisiana, Oklahoma, Mississippi and New Mexico may try to assert or expand jurisdiction on those lines, it is not likely that the assertion or expansion of that jurisdiction would have a significant effect on the Partnership's operations in those states because all tend to apply Federal regulations to natural gas pipeline facilities without numerous additional state-specific requirements.

        Gathering Pipeline Regulation.    Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. The Partnership owns a number of natural gas pipelines that it believes 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 classification and regulation of the Partnership's gathering facilities, for purposes of rate regulation to the extent it provides NGPA Section 311 services over such 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.

        The Partnership is 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 the Partnership contracts to purchase or transport natural gas.

        Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. The Partnership's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. The Partnership's gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Partnership cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        Sales of Natural Gas.    The price at which the Partnership sells natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The Partnership's sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules

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and regulations affecting those segments of 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 and these initiatives generally reflect less extensive regulation. The Partnership cannot predict the ultimate impact of these regulatory changes on its natural gas marketing operations, and we note that some of FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. The Partnership does not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.

Environmental Matters

        General.    The Partnership's operation and the Partnership's possible future operation of processing and fractionation plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionation 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 the Partnership's overall costs of doing business, including cost of planning, constructing, and operating plants, pipelines, and other facilities. Included in the Partnership's construction and operation costs are capital cost items necessary to maintain or upgrade equipment and facilities. The Partnership will likely incur similar costs upon its acquisition of assets if it acquires operating assets.

        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. While the Partnership believes that it currently holds material governmental approvals required to operate its major facilities, the Partnership is currently evaluating and updating permits for certain of its facilities that primarily were obtained in recent acquisitions. As part of the regular overall evaluation of its operations, the Partnership has implemented procedures to and are presently working to ensure that all governmental approvals, for both recently acquired facilities and existing operations, are updated as may be necessary. The Partnership believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on its operating results or financial condition.

        The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with the Partnership's possible future operations, and the Partnership cannot assure you that it will not incur significant costs and liabilities including those relating to claims for damage to property and persons as a result of such upsets, releases, or spills. In the event of future increases in costs, the Partnership may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject the Partnership to substantial expense, including both the cost to comply with applicable laws and regulations and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to property. The

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Partnership will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and in order to minimize the costs of such compliance.

        Hazardous Substance and Waste.    To a large extent, the environmental laws and regulations affecting the Partnership's possible future operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, 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 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 future, ordinary operations, we may 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.

        The Partnership also generates, and may in the future 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. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.

        The Partnership currently owns or leases, and has in the past owned or leased, and in the future the Partnership may own or lease, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of on or under various properties owned or leased by the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which

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such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership 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.

        The Partnership recently acquired two assets from DEFS that have environmental contamination, including a gas plant in Montgomery County, near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the Partnership's purchase agreement, Duke has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, the remediation costs associated with the Conroe site will be covered by agreements with TRC Companies and AIG. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.

        Air Emissions.    The Partnership's operations are, and the Partnership's possible future operations will likely be, 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. As a result of these amendments, the Partnership's processing and fractionating plants, pipelines, and storage facilities or any of its future assets that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. Such requirements, if applicable to our operations, could cause the Partnership 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 the Partnership's facilities and which may apply to some of its possible future facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although the Partnership can give no assurances, the Partnership believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on its financial condition or operating results.

        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 Cl