XTXI Crosstex Energy, Inc. (MM)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission file number: 000-50536

 

 

(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:

 

None.

 

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o

 

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  o      No  þ

 

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o

 

Indicate by check mark 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.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $902,981,774 on June 29, 2007, based on $28.73 per share, the closing price of the Common Stock as reported on the NASDAQ Global Select Market on such date.

 

At February 16, 2008, there were 46,317,703 shares of common stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Portions of the Registrant’s Proxy Statement relating to its 2007 Annual Stockholders’ Meeting to be filed with the Securities and Exchange Commission are incorporated by reference herein into Part III of this Report.

 

 

TABLE OF CONTENTS

 

DESCRIPTION

 

PART I

 

 

 

If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we expect to continue 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 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 and natural gas liquids, or NGLs, improving the profitability of its assets by increasing their utilization while controlling costs; accomplishing economies of scale through new construction or expansion opportunities in its core operating areas and maintaining financial flexibility to take advantage of opportunities. If the Partnership is successful in implementing this strategy, we believe the total amount of cash distributions it makes will increase and our share of those distributions will also increase. Under its current capital structure, each $0.01 per unit increase in distributions by the Partnership increases its total quarterly distribution by $827,000 and we would receive $578,000 or 70% of that increase.

 

So long as we own the Partnership’s general partner, under the terms of an omnibus agreement with the Partnership we are prohibited 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:

 

 

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 an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and NGLs. It 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 NGLs, fractionates NGLs into purity products and markets

those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. It purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. It operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee arrangements. In addition, it 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 has two operating segments, Midstream and Treating. The Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and NGLs, while the Treating division focuses on the removal of impurities from natural gas to meet pipeline quality specifications. The primary Midstream assets include over 5,000 miles of natural gas gathering and transmission pipelines, 12 natural gas processing plants and four fractionators. The 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 transmission pipelines primarily receive natural gas from the Partnership’s gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The processing plants remove NGLs from a natural gas stream and the Partnership’s fractionators separate the NGLs into separate NGL products, including ethane, propane, iso- and normal butanes and natural gasoline. The primary Treating assets include approximately 225 natural gas amine-treating plants and 55 dew point control plants. The Partnership’s natural gas treating plants remove carbon dioxide and hydrogen sulfide from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications. See Note 16 to the consolidated financial statements for financial information about these operating segments.

 

Set forth in the table below is a list of the Partnership’s significant acquisitions since January 1, 2003.

 

 

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

 

/d = per day

Bcf = billion cubic feet

Btu = British thermal units

Mcf = thousand cubic feet

MMBtu = million British thermal units

MMcf = million cubic feet

NGL = natural gas liquid

Capacity volumes for the Partnership’s facilities are measured based on physical volume and stated in cubic feet (Bcf, Mcf or MMcf). Throughput volumes are measured based on energy content and stated in British thermal units (Btu or MMBtu). A volume capacity of 100 MMcf generally correlates to volume throughput of 100,000 MMBtu.

 

Business Strategy

 

The Partnership’s strategy is to increase distributable cash flow per unit by accomplishing economies of scale through new construction or expansion in core operating areas, such as its expansion projects located in north Louisiana and north Texas as discussed in “Recent Acquisitions and Expansion” below; improving the profitability of its assets by increasing its utilization while controlling costs; making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas and NGLs; and maintaining financial flexibility to take advantage of opportunities. The Partnership believes the expanded scope of its operations, combined with a continued high level of drilling in its principal geographic areas, should present opportunities for continued expansion in existing areas of operation as well as opportunities to acquire or develop assets in new geographic areas that may serve as a platform for future growth. Key elements of our strategy include the following:

 

 

Recent Acquisitions and Expansion

 

North Texas Assets.   The Partnership’s NTP, which commenced service in April 2006, consists of a 133-mile pipeline and associated gathering lines from an area near Fort Worth, Texas to a point near Paris, Texas. The initial capacity of the NTP was approximately 250 MMcf/d. In 2007, it expanded the capacity on the NTP to a total of approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos and other markets. The Partnership is planning to interconnect the NTP with a new interstate gas pipeline to be constructed by Midcontinent Express Pipeline LLC and known as the Midcontinent Express Pipeline. The Midcontinent Express Pipeline is expected to be in service in March 2009. As of December 2007, the total throughput on the NTP was approximately 290,000 MMBtu/d. The NTP also will interconnect with a new intrastate gas pipeline to be constructed by Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing Pipeline. The Partnership has committed to contract for 150,000 MMBtu/d for ten years of firm transportation capacity on the Gulf Crossing Pipeline when it commences service, which is expected in the fourth quarter of 2008. The Gulf Crossing Pipeline and the Midcontinent Express Pipeline will provide customers access to premium midwest and east coast markets.

 

On June 29, 2006, the Partnership expanded its operations in the north Texas area through its acquisition of the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.3 million. The acquired systems, which is referred to in conjunction with the NTP and other facilities in the area as the Partnership’s north Texas assets, included gathering pipeline, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that acquisition, approximately 160,000 net acres previously owned by Chief and acquired by Devon Energy Corporation, or Devon, simultaneously with its acquisition, as well as 60,000 net acres owned by other producers, were dedicated to the systems. Immediately following the closing of the Chief acquisition, the Partnership began expanding its north Texas pipeline gathering system. Since the date of the acquisition through December 31, 2007, the Partnership connected 286 new wells to its gathering system and increased the dedicated acreage owned by other producers. In addition, the Partnership has a total of 90,000 horsepower of compression to handle the increased volumes and provide low pressure gathering service. In September 2007, the Partnership increased processing capacity in the area by constructing a 200 MMcf/d cryogenic processing plant, referred to as the Silver Creek plant, in addition to its 55 MMcf/d cryogenic processing plant, referred to as the Azle plant, and its 30 MMcf/d processing plant, known as the Goforth plant. The Partnership has also installed two 40 gallon per minute and one 100 gallon per minute amine treating plants to provide carbon dioxide removal capability. As of December 2007, the capacity of the Partnership’s north Texas gathering system was approximately 668 MMcf/d and total throughput on its north Texas gathering systems had increased from approximately 115,000 MMBtu/d at the time of the Chief acquisition to approximately 525,000 MMBtu/d for the month of December 2007.

 

The Partnership is currently constructing a new 29-mile natural gas gathering pipeline in north Johnson County, Texas, to provide greater takeaway capacity to natural gas producers in the Barnett Shale. The system will include low pressure and high pressure gathering pipelines with an estimated capacity of approximately 400 MMcf/d when all phases of the pipeline are complete, which is planned for the second quarter of 2008. The initial phase of this project was completed in September 2007 and the facilities were transporting approximately 83,000 MMBtu/d in the fourth quarter of 2007.

 

North Louisiana Expansion Project.   In April 2007, the Partnership completed construction and commenced operations on its north Louisiana expansion, which is an extension of its LIG system, designed to increase take-away pipeline capacity to the producers developing natural gas in the fields south of Shreveport, Louisiana. The north Louisiana expansion consists of approximately 63 miles of 24” mainline with 9 miles of 16” gathering lateral pipeline and 10,000 horsepower of new compression. The capacity of the expansion is approximately 240 MMcf/d, and, as of December 31, 2007, the expansion was flowing at approximately 225,000 MMBtu/d. Interconnects on the

north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission and Trunkline Gas.

 

Other Developments

 

Partnership’s Issuance of Common Units.   On December 19, 2007, the Partnership issued an aggregate of 1,800,000 common units representing limited partner interests at a price of $33.28 per unit for net proceeds of $57.6 million. In addition, Crosstex Energy GP, L.P. made a general partner contribution of $1.2 million in connection with this issuance to maintain its 2% general partner interest.

 

Issuance of Senior Subordinated Series D Units.   On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests in a private offering for net proceeds of approximately $99.9 million. The senior subordinated series D units were issued at $25.80 per unit, which represented a discount of approximately 25% to the market value of common units on such date. The discount represented an underwriting discount plus the fact that the units will not receive a distribution nor be readily transferable for two years. Crosstex Energy GP, L.P. made a general partner contribution of $2.7 million in connection with the issuance to maintain its 2% general partner interest. The senior subordinated series D units will automatically convert into common units on March 23, 2009. The senior subordinated series D units are not entitled to distributions of available cash or allocation of net income/loss from the Partnership until March 23, 2009.

 

Partnership’s Bank Credit Facility.   In September 2007, the Partnership increased its borrowing capacity under its bank credit facility from $1.0 billion to $1.185 billion.

 

Midstream Segment

 

Gathering, Processing and Transmission.   The Partnership’s primary Midstream assets include north Texas assets, south Texas assets, Louisiana assets, and Mississippi assets. These systems, in the aggregate, consist of over 5,000 miles of pipeline, 12 natural gas processing plants and four fractionators and contributed approximately 85% and 79% of the gross margin in 2007 and 2006, respectively.

 

 

 

 

 

 

 

 

Other Midstream assets and activities include:

 

 

Treating Segment

 

The Partnership operates (or leases to producers for operation) treating plants that 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 treating division contributed approximately 15% and 21% of the Partnership’s gross margin in 2007 and 2006, respectively. During 2006, the Partnership spent an aggregate of $58.0 million in two separate acquisitions to acquire 55 treating plants, 10 dew point control plants and related spare parts inventory. In 2007, the Partnership acquired the remaining ownership interest in seven additional treating plants, in which it already owned a 50% interest, for approximately $1.5 million. At December 31, 2007, the Partnership had approximately 190 treating and dew point control plants in operation. Pipeline companies have begun enforcing gas quality specifications to lower the dew point of the gas they receive and transport. A higher relative dew point can sometimes cause liquid hydrocarbons to condense in the pipeline and cause operating problems and gas quality issues to the downstream markets. Hydrocarbon dew point plants are skid mounted process equipment that remove these hydrocarbons. Typically these plants use a Joules-Thompson expansion process to lower the temperature of the gas stream and collect the liquids before they enter the downstream pipeline. The Partnership’s Treating division views dew point control as complementary to its treating business.

 

The Partnership believes it has the largest gas treating operation in the Texas and Louisiana gulf coast. Natural gas from certain formations in the Texas gulf coast, as well as other locations, is high in carbon dioxide, which generally needs to be removed before introduction of the gas into transportation pipelines. Many of its 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. In cases where producers pay the Partnership to operate the treating facilities, it either charges a fixed rate per Mcf of natural gas treated or a fixed monthly fee.

 

The Partnership also owns an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas, and which is accounted for as part of the Treating division. The Partnership is not the operator of the plant. 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, primarily those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.68 for each Mcf of carbon dioxide returned. The owners of the Seminole plant also receive 48% of the NGLs produced by the plant. The plant operator has commenced expansion of the plant’s capacity, which is expected to be in service in the first quarter of 2009, and as an interest owner in the plant, the Partnership is participating in the capital costs for such expansion.

The Partnership’s treating growth strategy is based on the belief that if gas prices remain at recent levels, producers will be encouraged to drill deeper gas formations. It believes the gas recovered from these formations is more likely to be high in carbon dioxide, a contaminant that generally needs to be removed before introduction into transportation pipelines. When completing a well, producers place a high value on immediate equipment availability, as they can more quickly begin to realize cash flow from a completed well. The Partnership believes its track record of reliability, current availability of equipment and its strategy of sourcing new equipment gives it a significant advantage in competing for new treating business.

 

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 remove the impurities from the gas. After mixing, gas and reacted 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.

 

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 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 and transmission pipelines to ensure that it meets pipeline quality specifications. Pipeline companies have begun enforcing gas quality specifications to lower the dew point of the gas they receive and transport. A higher relative dew point can sometimes cause liquid hydrocarbons to condense in the pipeline and cause operating problems and gas quality issues to the downstream markets. Hydrocarbon dew point plants are skid mounted process equipment that remove these hydrocarbons. Typically these plants use a Joules-Thompson expansion process to lower the temperature of the gas stream and collect the liquids before they enter the downstream pipeline. The Partnership’s Treating division views dew point control as complementary to its treating business.

 

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 produced by a well may not be 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.

 

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

 

Supply/Demand Balancing

 

As the Partnership purchases natural gas, it normally establishes a margin by selling natural gas for physical delivery to third-party users. It can also use over-the-counter derivative instruments or enter into a future delivery obligation under futures contracts on the New York Mercantile Exchange. Through these transactions, it 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. Its 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 for natural gas and NGLs is highly competitive. The Partnership faces strong competition in acquiring new natural gas supplies and in the marketing and transportation of natural gas and NGLs. Its competitors include major integrated oil companies, interstate and intrastate pipelines and other natural gas gatherers and processors. Competition for natural gas supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. Many of its competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do. The Partnership’s competition will likely differ in different geographic areas.

 

The Partnership’s gas treating operations face competition from manufacturers of new treating and dew point control plants and from a small number of regional operators that provide plants and operations similar to the Partnership. It also faces competition from vendors of used equipment that occasionally operate plants for producers. In addition, the Partnership routinely loses business to gas gatherers who have underutilized treating or processing capacity and can take the producers’ gas without requiring wellhead treating. The Partnership may also lose wellhead treating opportunities to blending. Some pipeline companies have the limited ability to waive their quality specifications and allow producers to deliver their contaminated gas untreated. This is generally referred to as blending because of the receiving company’s ability to blend this gas with cleaner gas in the pipeline such that the resulting gas meets pipeline specification.

 

In marketing natural gas and NGLs, 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 the Partnership.

 

The Partnership faces strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses, and results in fewer commitments and lower returns for new pipelines or other development projects. Many of its competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. The Partnership’s competition differs by region and by the nature of the business or the project involved.

Natural Gas Supply

 

The Partnership’s transmission pipelines have connections with major interstate and intrastate pipelines, which it believes have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of gathering systems, the Partnership evaluates well and reservoir data publicly available or furnished by producers or other service providers to determine the availability of natural gas supply for the systems and/or obtain a minimum volume commitment from the producer that results in a rate of return on the investment. Based on these facts, the Partnership believes that there should be adequate natural gas supply to recoup the investment with an adequate rate of return. It does not routinely obtain independent evaluations of reserves dedicated to its systems due to the cost and relatively limited benefit of such evaluations. Accordingly, it 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 purchase and resale of gas exposes the Partnership 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, 2007, the Partnership had one customer that individually accounted for approximately 11.8% of consolidated revenues. While this customer represents a significant percentage of consolidated revenues, the loss of this customer would not have a material impact on its results of operations.

 

Regulation

 

Regulation by FERC of Interstate Natural Gas Pipelines.   The Partnership does not own any interstate natural gas pipelines, so the FERC does not directly regulate its operations under the National Gas Act, or NGA. However, FERC’s regulation of interstate natural gas pipelines influences certain aspects of its business and the market for its products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

 

 

The rates, terms and conditions of service under which the Partnership transports natural gas in its pipeline systems in interstate commerce are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. Rates for services provided under Section 311 of the NGPA may not exceed a “fair and equitable rate”, as defined in the NGPA. The rates are generally subject to review every three years by the FERC or by an appropriate state agency. Rates for interstate services provided under NGPA Section 311 on our south Texas, Louisiana and Mississippi pipeline systems were each subject to review in 2006 and no substantial changes were made to their rates. There were no rate reviews in 2007.

 

Intrastate Pipeline Regulation.   The Partnership’s 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. 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.

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 we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. 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.

 

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 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. We cannot predict the ultimate impact of these regulatory changes on the Partnership’s 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. We do not believe that the Partnership will be affected by any such FERC action materially differently than other natural gas marketers with whom they compete.

 

Environmental Matters

 

General.   The Partnership’s operation of treating, processing and fractionation plants, pipelines and associated facilities in connection with the gathering, treating 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 its 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. Similar costs are likely upon any future acquisition of 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 we believe that the Partnership currently holds all material governmental approvals required to operate its major facilities, the Partnership is currently evaluating and updating permits for certain of its facilities specifically including those obtained in recent acquisitions. As part of the regular overall evaluation of its operations, the Partnership has implemented procedures and is presently working to ensure that all governmental approvals, for both recently acquired facilities and existing operations, are updated as may be necessary. We believe that the Partnership’s 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 we cannot assure you that the Partnership 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 its customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subjects 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 Partnership will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs.

 

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 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, the Partnership may generate wastes that may fall within the definition of a “hazardous substance.” The Partnership may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. The Partnership has not received any notification that it 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 it 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 the Partnership’s capital expenditures or plant operating expenses.

 

The Partnership currently owns or leases, and has in the past owned or leased, and in the future may own or lease, properties that have been used over the years for natural gas gathering, treating or processing and for NGL fractionation, transportation or 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 the Partnership had no control as to such entities’ handling of hydrocarbons or other wastes and the manner in which 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 acquired the south Louisiana processing assets from El Paso in November 2005. One of the acquired locations, the Cow Island Gas Processing Facility, has a known active remediation project for benzene

contaminated groundwater. The cause of contamination was attributed to a leaking natural gas condensate storage tank. The site investigation and active remediation being conducted at this location is under the guidance of the Louisiana Department of Environmental Quality (LDEQ) based on the Risk-Evaluation and Corrective Action Plan Program (RECAP) rules. In addition, the Partnership is working with both the LDEQ and the Louisiana State University, Louisiana Water Resources Research Institute, on the development and implementation of a new remediation technology that will drastically reduce the remediation time as well as the costs associated with such remediation projects. As of December 31, 2007, the Partnership had incurred approximately $0.5 million in such remediation costs, of which $0.4 million has already been paid. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to the Partnership’s ownership, these costs were accrued as part of the purchase price.

 

The Partnership acquired LIG Pipeline Company, and its subsidiaries, on April 1, 2004 from American Electric Power Company (AEP). Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. AEP has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third-party company that specializes in remediation work. The Partnership does not expect to incur any material liability in connection with the remediation associated with this site.

 

The Partnership acquired assets from Duke Energy Field Services, L.P. (DEFS) in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, contamination from historical operations had been identified at levels that exceeded the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million. Under the purchase and sale agreement, DEFS retained the liability for cleanup of the Conroe site. Moreover, DEFS has entered into an agreement with a third-party company pursuant to which the remediation costs associated with the Conroe site have been assumed by this third-party company that specializes in remediation work. The Partnership does not expect to incur any material liability in connection with the remediation associated with these sites.

 

Air Emissions.   The Partnership’s current and 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 gathering, treating and processing of natural gas, fractionation and storage of NGLs, or facilities therefor 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 the Partnership’s operations, could cause capital expenditures to be incurred 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 facilities and which may apply to some of the Partnership’s 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 we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on the Partnership’s 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 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. The Partnership believes that it is 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 its results of operations.

 

Employee Safety.   The Partnership is 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. The Partnership believes that its 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.   The Partnership’s pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, and the Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004 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. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. In addition, the TRRC regulates the Partnership’s pipelines in Texas under its own pipeline integrity management rules. The Texas rule includes certain transmission and gathering lines based upon pipeline diameter and operating pressures. The Partnership believes that its pipeline operations are in substantial compliance with applicable HLPSA and PIM requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA or PIM requirements will not have a material adverse effect on its results of operations or financial positions.

 

Office Facilities

 

In addition to the Partnership’s gathering and treating facilities discussed above, the Partnership occupies approximately 95,400 square feet of space at its executive offices in Dallas, Texas under a lease expiring in June 2014 and approximately 25,100 square feet of office space for the Partnership’s south Louisiana operations in Houston, Texas with lease terms expiring in January 2013. In November 2007, the Partnership opened approximately 11,800 square feet of office space for its north Texas operations in Fort Worth, Texas, with lease terms expiring in April 2013.

 

Employees

 

As of December 31, 2007, the Partnership (through its subsidiaries) employed approximately 700 full-time employees. Approximately 360 of the employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. The Partnership is not party to any collective bargaining agreements, and has not had any significant labor disputes in the past. We believe that the Partnership has good relations with its employees.

 

Our cash flow consists almost exclusively of distributions from Crosstex Energy, L.P.

 

Our only cash-generating assets are our partnership interests in Crosstex Energy, L.P. Our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners. The amount of cash that the Partnership can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond its control, including:

 

 

We are largely prohibited from engaging in activities that compete with the Partnership.

 

So long as we own the general partner of the Partnership, 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 its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. This exception for competitive activities is relatively limited. Although we have no current intention of pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement such as competitive opportunities that the Partnership declines to pursue or permitted activities that are not competition with the Partnership, the provisions of the omnibus agreement may, in the future, limit activities that we would otherwise pursue.

 

In our corporate charter, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that hold a majority of our common stock.

 

In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to:

 

 

 

As a result of this renunciation, these officers, directors and stockholders should not be deemed to be breaching any fiduciary duty to us if they or their affiliates or associates pursue opportunities presented as described above.

 

Although we control the Partnership, the general partner owes fiduciary duties to the Partnership and the unitholders.

 

Conflicts of interest exist and may arise in the future as a result of the relationship between us and our affiliates, including the general partner, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of Crosstex Energy GP, LLC have fiduciary duties to manage the general partner in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and its limited partners. The board of directors of Crosstex Energy GP, LLC will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders.

 

For example, conflicts of interest may arise in the following situations:

 

 

If the general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of the Partnership, its value, and therefore the value of our common stock, could decline.

 

The general partner may make expenditures on behalf of the Partnership for which it will seek reimbursement from the Partnership. In addition, under Delaware partnership law, the general partner, in its capacity as the general partner of the Partnership, has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the general partner. To the extent the general partner incurs obligations on behalf of the Partnership, it is entitled to be reimbursed or indemnified by the general partner. In the event that the Partnership is unable or unwilling to reimburse or indemnify the general partner, the general partner may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common stock.

 

Acquisitions in the Partnership typically increase debt and subject it to other substantial risks, which could adversely affect results of operations.

 

The Partnership’s future financial performance will depend, in part, on its ability to make acquisitions of assets and businesses at attractive prices. From time to time, the Partnership will evaluate and seek to acquire assets or businesses that it believes complements existing business and related assets. The Partnership may acquire assets or businesses that it plans to use in a manner materially different from their prior owner’s use. Any acquisition involves potential risks, including:

 

 

 

Management’s assessment of these risks is necessarily inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect the Partnership’s operations and cash flows. If the Partnership consummates any future acquisition, its 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 the Partnership will consider in determining the application of these funds and other resources.

 

The Partnership continues to consider large acquisition candidates and transactions. The integration, financial and other risks discussed above will be amplified if the size of its future acquisitions increases.

 

The Partnership’s acquisition strategy is based, in part, on expectation of ongoing divestitures of gas processing and transportation assets by large industry participants. A material decrease in such divestitures will limit opportunities for future acquisitions and could adversely affect the Partnership’s growth plans.

 

The Partnership is vulnerable to operational, regulatory and other risks associated with its assets including, with respect to its south Louisiana and the Gulf of Mexico assets, the effects of adverse weather conditions such as hurricanes, because a significant portion of its assets are located in south Louisiana.

 

Operations and revenues will be significantly impacted by conditions in south Louisiana because the Partnership has a significant portion of its assets located in south Louisiana. This concentration of activity makes the Partnership more vulnerable than many of its competitors to the risks associated with Louisiana and the Gulf of Mexico, including:

 

 

Because a significant portion of the Partnership’s operations could experience the same condition at the same time, these conditions could have a relatively greater impact on results of operations than they might have on other midstream companies who have operations in a more diversified geographic area.

 

In addition, the Partnership’s operations in south Louisiana are dependent upon continued conventional and deep shelf drilling in the Gulf of Mexico. The deep shelf in the Gulf of Mexico is an area that has had limited historical drilling activity. This is due, in part, to its geological complexity and depth. Deep shelf development is more expensive and inherently more risky than conventional shelf drilling. A decline in the level of deep shelf drilling in the Gulf of Mexico could have an adverse effect on the Partnership’s financial condition and results of operations.

 

The Partnership’s profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile.

 

The Partnership is subject to significant risks due to fluctuations in commodity prices. These risks are based upon three components of business: (1) it purchases certain volumes of natural gas at a price that is a percentage of a relevant index; (2) certain processing contracts for its Gregory system and its Plaquemine and Gibson processing plants expose the Partnership to natural gas and NGL commodity price risks; and (3) part of its fees from the Conroe and Seminole gas plants as well as those acquired in the El Paso acquisition are based on a portion of the NGLs produced, and, therefore, is subject to commodity price risks.

 

The margins the Partnership realizes from purchasing and selling a portion of the natural gas that it transports through its pipeline systems decrease in periods of low natural gas prices because gross margins related to such purchases are based on a percentage of the index price. For the years ended December 31, 2006 and 2007, the

Partnership purchased approximately 5.9% and 4.3%, respectively, of its gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact on its results of operations.

 

A portion of the Partnership’s profitability is affected by the relationship between natural gas and NGL prices. For a component of the Gregory system and the Plaquemine plant and Gibson plant volumes, natural gas is purchased, processed and NGLs are extracted, and then the processed natural gas and NGLs are sold. A portion of profits from the plants acquired in the El Paso acquisition is dependent on NGL prices and elections by the Partnership and the producers. In cases where the Partnership processes gas for producers when they have the ability to decide whether to process their gas, it may elect to receive a processing fee or it may retain and sell the NGLs and keep the producer whole on its sale of natural gas. Since the Partnership extracts energy content, which is measured in Btu’s, from the gas stream in the form of the liquids or consume it as fuel during processing, the Partnership reduces the Btu content of the natural gas. Accordingly, margins under these arrangements can be negatively affected in periods in which the value of natural gas is high relative to the value of NGLs.

 

In the past, the prices of natural gas and NGLs have been extremely volatile and this volatility is expected to continue. For example, in 2006, the NYMEX settlement price for natural gas for the prompt month contract ranged from a high of $11.43 per MMBtu to a low of $4.20 per MMBtu. In 2007, the same index ranged from $7.59 per MMBtu to $5.43 per MMBtu. A composite of the OPIS Mt. Belvieu monthly average liquids price based upon our average liquids composition in 2006 ranged from a high of approximately $1.20 per gallon to a low of approximately $0.90 per gallon. In 2007, the same composite ranged from approximately $1.58 per gallon to approximately $0.92 per gallon. As further discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, the Partnership’s processing facilities realized favorable processing margins during 2007, but due to this volatility in the prices of natural gas and NGLs, processing margins may be lower in future periods if NGL markets weaken.

 

The Partnership may not be successful in balancing purchases and sales. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause purchases and sales not to be balanced. If purchases and sales are not balanced, the Partnership will face increased exposure to commodity price risks and could have increased volatility in operating income.

 

The markets and prices for residue gas and NGLs depend upon factors beyond the Partnership’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

 

 

The Partnership must continually compete for natural gas supplies, and any decrease in its supplies of natural gas could adversely affect its financial condition and results of operations.

 

If the Partnership is unable to maintain or increase the throughput on its systems by accessing new natural gas supplies to offset the natural decline in reserves, business and financial results could be materially, adversely affected. In addition, the Partnership’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in currently connected supplies.

In order to maintain or increase throughput levels in the Partnership’s natural gas gathering systems and asset utilization rates at its treating and processing plants, it must continually contract for new natural gas supplies. The Partnership may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting its ability to connect new wells to its gathering facilities include success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near its gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Tax policy changes could have a negative impact on drilling activity, reducing supplies of natural gas available to the Partnership’s systems. The Partnership has no control over producers and depends on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production or in the level of drilling activity in its principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on the Partnership’s results of operations and financial position.

 

A substantial portion of the Partnership’s assets are connected to natural gas reserves that will decline over time, and the cash flows associated with those assets will decline accordingly.

 

A substantial portion of the Partnership’s assets, including gathering systems and treating plants, is dedicated to certain natural gas reserves and wells for which the production will naturally decline over time. Accordingly, cash flows associated with these assets will also decline. If the Partnership is unable to access new supplies of natural gas either by connecting additional reserves to existing assets or by constructing or acquiring new assets that have access to additional natural gas reserves, cash flows may decline.

 

Growing the Partnership’s business by constructing new pipelines and processing and treating facilities subjects the Partnership to construction risks, risks that natural gas supplies will not be available upon completion of the facilities and risks of construction delay and additional costs due to obtaining rights-of-way.

 

One of the ways the Partnership intends to grow business is through the construction of or additions to existing gathering systems and construction of new pipelines and gathering, processing and treating facilities. The construction of pipelines and gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed the Partnership’s expectations. Generally, the Partnership may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, the Partnership may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. The Partnership may also rely on estimates of proved reserves in the decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve the expected investment return, which could adversely affect its results of operations and financial condition. In addition, the Partnership faces the risks of construction delay and additional costs due to obtaining rights-of-way and local permits and complying with city ordinances, particularly as it expands operations into more urban, populated areas such as the Barnett Shale.

 

The Partnership has limited control over the development of certain assets because it is not the operator.

 

As the owner of non-operating interests in the Seminole gas processing plant, the Partnership does not have the right to direct or control the operation of the plants. As a result, the success of the activities conducted at this plant, which is operated by a third party, may be affected by factors outside of the Partnership’s control. The failure of the third-party operator to make decisions, perform its services, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations affecting these plants, including environmental laws and regulations, in a proper manner could result in material adverse consequences to the Partnership’s interest and adversely affect the Partnership’s results of operations.

The Partnership expects to encounter significant competition in any new geographic areas into which it seeks to expand and the ability to enter such markets may be limited.

 

As the Partnership expands operations into new geographic areas, it expects to encounter significant competition for natural gas supplies and markets. Competitors in these new markets will include companies larger than the Partnership, which have both lower capital costs and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, the Partnership may not be able to successfully develop acquired assets and markets located in new geographic areas and the Partnership’s results of operations could be adversely affected.

 

The Partnership is exposed to the credit risk of customers and counterparties, and a general increase in the nonpayment and nonperformance by its customers could have an adverse effect on its financial condition and results of operations.

 

Risks of nonpayment and nonperformance by the Partnership’s customers is a major concern in its business. The Partnership is subject to risks of loss resulting from nonpayment or nonperformance by its customers. Any increase in the nonpayment and nonperformance by its customers could adversely affect results of the Partnership’s operations.

 

The Partnership may not be able to retain existing customers or acquire new customers, which would reduce revenues and limit future profitability.

 

The renewal or replacement of existing contracts with customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond the Partnership’s control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets it serves.

 

For the year ended December 31, 2007, approximately 53% of the Partnership’s sales of gas which were transported using its physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the basis of price. The inability of the Partnership’s management to renew or replace current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on its profitability.

 

The Partnership depends on certain key customers, and the loss of any of its key customers could adversely affect its financial results.

 

The Partnership derives a significant portion of its revenues from contracts with key customers. To the extent that these and other customers may reduce volumes of natural gas purchased under existing contracts, the Partnership would be adversely affected unless it was able to make comparably profitable arrangements with other customers. Agreements with key customers provide for minimum volumes of natural gas that each customer must purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Customers may default on their obligations to purchase the minimum volumes required under the applicable agreements.

 

The Partnership’s business involves many hazards and operational risks, some of which may not be fully covered by insurance.

 

The Partnership’s operations are subject to the many hazards inherent in the gathering, compressing, treating and processing of natural gas and storage of residue gas, including:

 

 

 

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of the Partnership’s related operations. The Partnership’s operations are concentrated in Texas, Louisiana and the Mississippi Gulf Coast, and a natural disaster or other hazard affecting this region could have a material adverse effect on its operations. The Partnership is not fully insured against all risks incident to its business. In accordance with typical industry practice, the Partnership does not have any property insurance on any of its underground pipeline systems that would cover damage to the pipelines. It is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. Business interruption insurance covers only the Gregory processing plant. If a significant accident or event occurs that is not fully insured, it could adversely affect operations and financial condition.

 

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact the Partnership’s results of operations and its ability to raise capital.

 

Terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect the Partnership’s operations in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. Instability in the financial markets as a result of terrorism, the war in Iraq or future developments could also affect the Partnership’s ability to raise capital.

 

Changes in the insurance markets attributable to the threat of terrorist attacks have made certain types of insurance more difficult for the Partnership to obtain. The Partnership’s insurance policies now generally exclude acts of terrorism. Such insurance is not available at what the Partnership considers to be acceptable pricing levels. A lower level of economic activity could also result in a decline in energy consumption, which could adversely affect revenues or restrict future growth.

 

Federal, state or local regulatory measures could adversely affect the Partnership’s business.

 

While FERC generally does not regulate any of the Partnership’s operations, FERC influences certain aspects of its business and the market for its products. The rates, terms and conditions of service under which the Partnership transports natural gas on its pipeline systems in interstate commerce are subject to FERC regulation under Section 311 of the NGPA. The Partnership’s 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. Should FERC or any of these state agencies determine that our rates for Section 311 transportation service or intrastate transportation service should be lowered, its business could be adversely affected.

 

The Partnership’s gas gathering activities generally are exempt from FERC regulation and NGA. 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 are subject to change based on future determinations by FERC and the courts. 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. 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. We cannot predict what effect, if any, such changes might have on the Partnership’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Other state and local regulations also affect the Partnership’s business. It is subject to ratable take and common purchaser statutes in the states where it operates. 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 have the effect of restricting the Partnership’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which it operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which the Partnership operates that have adopted some form of complaint-based regulation, like Oklahoma and Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

 

The states in which the Partnership conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of the Partnership’s gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to the Partnership’s natural gas transmission pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements.

 

Compliance with pipeline integrity regulations issued by the TRRC, or those issued by the United States Department of Transportation in December of 2003 could result in substantial expenditures for testing, repairs and replacement. TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. the Partnership’s costs relating to compliance with the required testing under the TRRC regulations were approximately $1.2 million, $1.1 million and $0.3 million for the years ended December 31, 2007, 2006 and 2005, respectively, and it expects the costs for compliance with TRRC and DOT regulations to be $8.9 million during 2008. If the Partnership’s pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then the Partnership may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

 

As the operations of the Partnership continue to expand into and around urban, populated areas, such as the Barnett Shale, it will have more compliance requirements with local ordinances and other restrictions imposed by cities and towns, such as noise ordinances and restrictions on facility locations and pressures. These requirements could result in increased costs and construction delays.

 

The Partnership’s business involves hazardous substances and may be adversely affected by environmental regulation.

 

Many of the operations and activities of the Partnership’s gathering systems, plants and other facilities, including the natural gas and processing liquids business in south Louisiana recently acquired from El Paso, are subject to significant federal, state and local environmental laws and regulations. These laws and regulations impose obligations related to air emissions and discharge of pollutants from the Partnership’s facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by the Partnership or locations to which it has sent wastes for treatment or disposal. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Strict, joint and several liability may be incurred under these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties through which the Partnership’s gathering systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

 

There is inherent risk of the incurrence of significant environmental costs and liabilities in the Partnership’s business due to its handling of natural gas and other petroleum products, air emissions related to the Partnership’s operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters

containing mercury. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase the Partnership’s compliance costs and the cost of any remediation that may become necessary. The Partnership may incur material environmental costs and liabilities. Furthermore, insurance may not provide sufficient coverage in the event an environmental claim is made against the Partnership.

 

The Partnership’s business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect the Partnership’s products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect the Partnership’s profitability.

 

The use of derivative financial instruments has in the past and could in the future result in financial losses or reduce income.

 

The Partnership uses over-the-counter price and basis swaps with other natural gas merchants and financial institutions, and it uses futures and option contracts traded on the New York Mercantile Exchange. Use of these instruments is intended to reduce exposure to short-term volatility in commodity prices. The Partnership could incur financial losses or fail to recognize the full value of a market opportunity as a result of volatility in the market values of the underlying commodities or if one of its counterparties fails to perform under a contract.

 

Due to the Partnership’s lack of asset diversification, adverse developments in gathering, transmission, treating, processing and commercial services businesses would materially impact its financial condition.

 

The Partnership relies exclusively on the revenues generated from its gathering, transmission, treating, processing and commercial services businesses, and as a result its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to its lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on financial condition and results of operations than if it maintained more diverse assets.

 

The Partnership’s success depends on key members of management, the loss or replacement of whom could disrupt its business operations.

 

The Partnership depends on the continued employment and performance of the officers of Crosstex Energy GP, LLC and key operational personnel. Crosstex Energy GP, LLC enters into employment agreements with each of its executive officers. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, the Partnership’s business operations could be materially adversely affected. The Partnership does not maintain any “key man” life insurance for any officers.

 

 

We believe that the Partnership has satisfactory title to all of its rights of way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of the Partnership’s assets or from the Partnership’s interest in these assets or should materially interfere with their use in the operation of the business.

 

 

 

PART II

 

The following table shows the high and low closing sales prices per share, as reported by the NASDAQ Global Select Market, for the periods indicated:

 

 

 

 

We intend to continue 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:

 

 

If the Partnership continues to be successful in implementing its business strategy and increasing distributions to its partners, we would expect to continue 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.

 

The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.

 

 

Performance Graph

 

The following graph sets forth the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Stock Index, and a peer group of publicly traded partners of publicly traded limited partnerships in the Midstream natural gas, natural gas liquids and propane industries from January 12, 2004, the date of our initial public offering, through December 31, 2007. The chart assumes that $100 was invested on January 12, 2004, with dividends reinvested. The peer group includes Alliance Holdings G.P., L.P. (initial public offering was in May 2006), Inergy Holdings, L.P. (initial public offering was in June 2005), Enterprise GP Holdings, L.P. (initial public offering was in August 2005) and Magellan Midstream Holdings, L.P. (initial public offering was in February 2006). Peers are assumed to perform the same as Crosstex Energy, Inc. prior to their respective initial public offerings.

 

 

The following table sets forth selected historical financial and operating data of Crosstex Energy, Inc. as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, Inc. The summary historical financial and operating include the results of operations of the Mississippi pipeline system and the Seminole processing plant beginning in June 2003, the LIG assets beginning in April 2004, the south Louisiana processing assets beginning November 2005, the Hanover assets beginning January 2006, the NTP beginning April 2006, the Midstream assets acquired from Chief beginning June 29, 2006 and other smaller acquisitions completed during 2006.

 

The table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

 

 

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 $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter, and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

 

Distributions by the Partnership have increased from $0.25 per unit for the quarter ended March 31, 2003 (its first full quarter of operation after its initial public offering) to $0.61 per unit for the quarter ended December 31, 2007. As a result, our distributions from the Partnership pursuant to our ownership of common units and subordinated units (excluding senior subordinated series C units) have increased from $2.5 million for the quarter ended March 31, 2003 to $6.1 million for the quarter ended December 31, 2007; our distributions pursuant to our 2% general partner interest have increased from $74,000 to $0.5 million; and our distributions pursuant to our incentive distribution rights have increased from zero to $7.3 million. The senior subordinated series C units were not entitled to receive distributions until they converted to common units in February 2008. As a result, we have increased our dividend from $0.10 per share for the quarter ended March 31, 2004 (giving effect to the three-for-one stock split on December 15, 2006) to $0.26 per share for the quarter ended December 31, 2007.

 

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. The interest owned by non-controlling partners’ share of income is reflected as an expense in our results of operations. We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Our consolidated results of operations are derived from the results of operations of the Partnership and also include our gains on the issuance of units in the Partnership, deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operation. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

 

The Partnership has two industry segments, Midstream and Treating, with a geographic focus in north Texas, in south Texas, in Louisiana and in Mississippi. The Partnership’s Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and NGLs, as well as providing certain producer services, while the Treating division focuses on the removal of contaminants from natural gas and NGLs to meet pipeline quality specifications. For the year ended December 31, 2007, 85% of the Partnership’s gross margin was generated in the Midstream division, with the balance in the Treating division. The Partnership focuses on gross margin to manage its business because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport, market or treat natural gas or NGLs for a fee. The Partnership buys and sells most of its natural gas at a fixed relationship to the relevant index price so margins are not significantly affected by changes in natural gas prices. As explained under “Commodity Price Risk” below, it enters into financial instruments to reduce volatility in gross margin due to price fluctuations.

 

During the past five years, the Partnership has grown significantly as a result of construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2003 through December 31, 2007, it has invested over $2.1 billion 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.

 

The Partnership’s Midstream segment margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities and the

volumes of NGLs handled at its fractionation facilities. Treating segment margins are largely a function of the number and size of treating plants as well as fees earned for removing impurities from NGLs at a non-operated processing plant. The Partnership generates revenues from six primary sources:

 

 

The bulk of the Partnership’s operating profits has historically derived from the margins it realizes for gathering and transporting natural gas and NGLs through its pipeline systems. Generally, the Partnership gathers and transports gas owned by others through its facilities for a fee, or it buys gas from a producer, plant, or transporter at either a fixed discount to a market index or a percentage of the market index, then transports and resells the gas. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index price at which the gas was purchased, and, if the Partnership is to be profitable, at a smaller discount or larger premium to the index than it was purchased. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership’s gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See “Commodity Price Risk” below for a discussion of how it manages its business to reduce the impact of price volatility.

 

Processing and fractionation revenues are largely fee based. Processing fees are largely based on either a percentage of the liquids volume recovered, or a fixed fee per unit processed. Fractionation and marketing fees are generally fixed per unit of product.

 

The Partnership generates treating revenues under three arrangements:

 

 

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

 

Acquisitions and Expansions

 

The Partnership has grown significantly through asset purchases and undertaking construction and expansion projects in recent years, which creates many of the major differences when comparing operating results from one period to another. The most significant asset purchases since January 2006 were the acquisitions of midstream assets from Chief Holdings LLC (Chief) in June 2006, the Hanover Compression Company treating assets in February 2006 and the acquisition of the amine treating business of Cardinal Gas Solutions L.P. in October 2006. In addition, internal expansion projects in north Texas and Louisiana have contributed to the increase in the Partnership’s business.

On June 29, 2006, the Partnership expanded its operations in the north Texas area through its acquisition of the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.3 million. The acquired systems, which is referred to in conjunction with the NTP and other facilities in the area as the Partnership’s north Texas assets, included gathering pipeline, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that acquisition, approximately 160,000 net acres previously owned by Chief and acquired by Devon Energy Corporation, or Devon, simultaneously with its acquisition, as well as 60,000 net acres owned by other producers, were dedicated to the systems. Immediately following the closing of the Chief acquisition, the Partnership began expanding its north Texas pipeline gathering system. Since the date of the acquisition through December 31, 2007, the Partnership connected 286 new wells to its gathering system and significantly increased the dedicated acreage owned by other producers. In addition, the Partnership has a total of 90,000 horsepower of compression to handle the increased volumes and provide low pressure gathering service. In September 2007, the Partnership increased processing capacity in the area by constructing a 200 MMcf/d cryogenic processing plant, referred to as the Silver Creek plant, in addition to its 55 MMcf/d cryogenic processing plant, referred to as the Azle plant, and its 30 MMcf/d processing plant, known as the Goforth plant. The Partnership has also installed two 40 gallon per minute and one 100 gallon per minute amine treating plants to provide carbon dioxide removal capability. The Partnership has total capacity of approximately 668 MMcf/d on our north Texas gathering assets and has increased total throughput on its north Texas gathering systems from approximately 115,000 MMBtu/d at the time of the Chief acquisition to approximately 525,000 MMBtu/d for the month of December 2007.

 

On February 1, 2006, the Partnership acquired 48 amine-treating plants from a subsidiary of Hanover Compression Company for $51.7 million.

 

On October 3, 2006, the Partnership acquired the amine-treating business of Cardinal Gas Solutions Limited Partnership for $6.3 million. The acquisition added 10 dew point control plants and 50% of seven amine-treating plants to its plant portfolio. On March 28, 2007, the Partnership acquired the remaining 50% interest in the amine-treating plants for approximately $1.5 million.

 

The Partnership’s NTP, which commenced service in April 2006, consists of a 133-mile pipeline and associated gathering lines from an area near Fort Worth, Texas to a point near Paris, Texas. The initial capacity of the NTP was approximately 250 MMcf/d. In 2007, the Partnership expanded the capacity on the NTP to a total of approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos and other markets. As of December 2007, the total throughput on NTP was approximately 290,000 MMBtu/d. The NTP will interconnect with a new intrastate gas pipeline to be constructed by Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing Pipeline. The Gulf Crossing Pipeline will provide our customers access to premium midwest and east coast markets. The Partnership has committed to contract for 150,000 MMBtu/d for ten years of firm transportation capacity on the Gulf Crossing Pipeline when it commences service, which is expected in the fourth quarter of 2008.

 

The Partnership is currently constructing a new 29-mile natural gas gathering pipeline in north Johnson County, Texas, to provide greater takeaway capacity to natural gas producers in the Barnett Shale. The system will include low pressure and high pressure gathering pipelines with an estimated capacity of approximately 400 MMcf/d when all phases of the pipeline are complete, which is planned for the second quarter of 2008. The initial phase of this project was completed in September 2007 and the facilities were transporting approximately 83,000 MMBtu/d in the fourth quarter of 2007.

 

In April 2007, the Partnership completed construction and commenced operations on its north Louisiana expansion, which is an extension of its LIG system, designed to increase take-away pipeline capacity to the producers developing natural gas in the fields south of Shreveport, Louisiana. The north Louisiana expansion consists of approximately 63 miles of 24” mainline with 9 miles of 16” gathering lateral pipeline and 10,000 horsepower of new compression. The capacity of the expansion is approximately 240 MMcf/d, and, as of December 31, 2007, the expansion was flowing at approximately 225,000 MMBtu/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission and Trunkline Gas.

Other Assets

 

We own two inactive gas plants in addition to our limited and general partner interests in the Partnership. The two gas plants are the Jonesville processing plant, which has been largely inactive since the beginning of 2001, and the Clarkson plant, acquired shortly before the Partnership’s initial public offering. In the third quarter of 2004, we fully impaired our investment in the Jonesville plant.

 

Impact of Federal Income Taxes

 

Crosstex Energy, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law. We expect to have significant amounts of taxable income allocated to us as a result of our investment in the Partnership’s units, particularly because of remedial allocations that will be made among the unitholders and because of the general partner’s incentive distribution rights, which we will benefit from as the sole owner of the general partner. Taxable income allocated to us by the Partnership will increase over the years as the ratio of income to distributions increases for all of the unitholders.

 

As of December 31, 2007 we have a net operating loss carryforward of $94.9 million for federal income taxes and state loss carryforwards of $39.6 million. We believe it is more likely than not that our future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire. Once these net operating loss carryforwards are fully utilized, we will have to pay tax on our federal taxable income at a maximum rate of 35.0% under current law. Thus, the amount of money available to make cash distributions to our stockholders will decrease markedly after we use all of our net operating loss carryforward.

 

Our use of this net operating loss carryforward will be limited if there is a greater than 50.0% change in our stock ownership over a three year period.

 

Commodity Price Risk

 

The Partnership’s 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 can 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 crude oil, NGL products and natural gas.

 

Profitability under the Partnership’s 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 profitability since the purchase price of a portion of the gas the Partnership buys 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 gas prices. However, on most of the gas bought and sold, 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, the changes are equal and offsetting.

 

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 the Partnership’s principal gathering and transmission systems and for its commercial services business for the year ended December 31, 2007.

 

 

 

The Partnership estimates that, due to the gas that it purchases at a percentage of index price, for each $0.50 per MMBtu increase or decrease in the price of natural gas, its gross margins increase or decrease by approximately $1.0 million on an annual basis (before consideration of hedge positions). As of December 31, 2007, it has hedged approximately 95% of its exposure to such fluctuations in natural gas prices for 2008 and approximately 34% of its exposure to such fluctuations for 2009. CELP expects to continue to hedge its exposure to gas prices when market opportunities appear attractive.

 

The Partnership processed approximately 75% of its volumes during 2007 at Eunice, Pelican, Sabine and Blue Water under “percent of proceeds” contracts, under which it receives as a fee a portion of the liquids produced, and 25% of its volume as fixed fee per unit processed. Under percent of proceeds contracts, it is exposed to changes in the prices of NGLs. For the years 2007 and 2006, it has purchased puts or entered into forward sales covering all of its anticipated minimum share of NGLs production. For 2008 we have hedges in place covering approximately 80% of the liquid volumes we expect to receive through May 2009.

 

The Partnership’s processing plants at Plaquemine and Gibson have a variety of processing contract structures. In general, the Partnership buys gas under keep-whole arrangements in which it bears the risk of processing, percentage-of-proceeds arrangements in which it receives a percentage of the value of the liquids recovered, and “theoretical” processing arrangements in which the settlement with the producer is based on an assumed processing result. Because the Partnership has the ability to bypass certain volumes when processing is uneconomic, it can limit its exposure to adverse processing margins. During periods when processing margins are favorable, the Partnership can substantially increase the volumes it is processing.

 

For the year ended December 31, 2007, the Partnership purchased a small amount (approximately 3.3%) 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. The Partnership purchased the remaining approximately 96.7% of the natural gas volumes on its Gregory system at a spot or market price less a discount that includes a fixed margin for gathering, 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.

 

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 for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.68 for each McF of carbon dioxide returned. Reinjected carbon dioxide is used in a tertiary oil recovery process in the field. The plant also receives 48% of the NGLs produced by the plant. Therefore, the Partnership has commodity price exposure due to variances in the prices of NGLs. During 2007, its share of NGLs totaled 5.2 million gallons at an average price of $1.23 per gallon.

 

Gas prices can also affect the Partnership’s 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, 2007 Compared to Year Ended December 31, 2006

 

Gross Margin and Profit on Energy Trading Activities.   Midstream gross margin was $326.5 million for the year ended December 31, 2007 compared to $218.2 million for the year ended December 31, 2006, an increase of $108.3 million, or 49.6%. This increase was primarily due to system expansions, increased system throughput and a favorable processing environment for natural gas and NGLs.

 

The Partnership acquired the NTG assets from Chief in June 2006. System expansion in the north Texas region and increased throughput on the North Texas Pipeline (NTP) contributed $64.5 million of gross margin growth during the year ended December 31, 2007 over the same period in 2006. The NTG and NTP assets accounted for $34.1 million and $16.6 million of this increase, respectively. The processing facilities in the region contributed an additional $13.3 million of this gross margin increase. Operational improvements, system expansion and increased volume on the LIG system coupled with optimization and integration with the south Louisiana processing assets contributed margin growth of $22.6 million for 2007. Volume increases on the Mississippi system contributed gross margin growth of $5.7 million. The Plaquemine and Gibson plants contributed margin growth of $9.9 million due to a favorable gas processing environment. The favorable gas processing margin also led to a combined $5.3 million margin increase on the Vanderbilt and Gulf Coast systems.

 

The favorable processing margins the Partnership realized during 2007 at several of its processing facilities may be higher than margins it may realize during future periods if the NGL markets do not remain as strong as they were during 2007. As discussed above under “-Commodity Price Risk” , the Partnership receives a portion of liquids processed or a percentage of the liquids recovered as a processing fee on a substantial portion of the gas processed through these plants. During periods when processing margins are favorable, as existed during 2007, it experiences higher processing margins. The Partnership has the ability to bypass certain volumes when processing is uneconomic so it can limit its exposure to adverse processing margins but processing margins will be lower during these periods.

 

In addition, the Partnership has the ability to buy gas from and to sell gas to various gas markets through its pipeline systems. During 2007 the Partnership was able to benefit from price differentials between the various gas markets by selling gas into markets with more favorable pricing thereby improving its Midstream gross margin. If these price differentials do not exist in future periods, Midstream gross margin may be lower.

 

Treating gross margin was $57.1 million for the year ended December 31, 2007 compared to $54.3 million for the same period in 2006, an increase of $2.8 million, or 5.1%. There were approximately 190 treating and dew point

control plants in service at December 31, 2007. This number was unchanged from December 31, 2006. Gross margin growth for the period is attributed to a higher average number of plants in service each month during 2007 compared to 2006.

 

Operating Expenses.   Operating expenses were $127.8 million for the year ended December 31, 2007 compared to $101.0 million for the year ended December 31, 2006, an increase of $26.8 million, or 26.5%. The increase in operating expenses primarily reflects costs associated with growth and expansion in the north Texas assets of $17.5 million, the south Texas assets of $1.8 million, the LIG and the north Louisiana expansion assets of $3.7 million, and Treating assets of $1.6 million. Operating expenses included $1.8 million of stock-based compensation expenses in 2007 compared to $1.1 million of stock-based compensation expense in 2006.

 

General and Administrative Expenses.   General and administrative expenses were $64.3 million for the year ended December 31, 2007 compared to $47.7 million for the year ended December 31, 2006, an increase of $16.6 million, or 34.8%. Additions to headcount associated with the requirements of NTP and NTG assets and the expansion in north Louisiana accounted for $8.9 million of the increase. Consulting for system and process improvements resulted in $2.8 million of the increase. General and administrative expenses included stock-based compensation expense of $10.2 million and $7.4 million in 2007 and 2006, respectively.

 

Gain/Loss on Derivatives.   We had a gain on derivatives of $5.7 million for the year ended December 31, 2007 compared to a gain of $1.6 million for the year ended December 31, 2006. The gain in 2007 includes a gain of $8.1 million associated with our basis swaps (including $7.0 million of realized gain) plus a net gain associated with storage financial transactions, third-party on-system and off-system financial transactions and ineffectiveness in our hedged derivatives of $0.6 million offset by a loss of $1.3 million associated with our processing margin hedges (all realized), a loss of $0.9 million related to our interest rate swaps and a loss of $0.8 million on puts acquired in 2005 related to the acquisition of the south Louisiana processing assets and as part of the LIG acquisition. As of December 31, 2007, the fair value of the puts was zero as all the put options have expired.

 

Gain/Loss on Sale of Property.   Assets sold during the year ended December 31, 2007 generated a net gain of $1.7 million as compared to a gain of $2.1 million during the year ended December 31, 2006. The gain in 2007 primarily related to the sale of inactive gas processing facilities acquired as part of the south Louisiana processing assets.

 

Depreciation and Amortization.   Depreciation and amortization expenses were $108.9 million for the year ended December 31, 2007 compared to $82.8 million for the year ended December 31, 2006, an increase of $26.1 million, or 31.6%. Midstream depreciation and amortization increased $25.8 million due to the NTP, NTG and north Louisiana expansion project assets.

 

Interest Expense.   Interest expense was $78.0 million for the year ended December 31, 2007 compared to $51.1 million for the year ended December 31, 2006, an increase of $27.0 million. The increase relates primarily to an increase in debt outstanding as a result of acquisitions and other growth projects. Net interest expense consists of the following (in millions):

 

 

Other Income.   Other income was $0.7 million for the year ended December 31, 2007 compared to $1.8 million for the year ended December 31, 2006. In 2006 we collected $1.6 million in excess of the carrying value of the Enron account receivable net of the allowance.

Gain on Issuance of Units of the Partnership.   As a result of the Partnership issuing common units in December 2007 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $7.5 million and we recognized a gain on issuance of such units. In 2006, we recognized a $19.0 million gain associated with the issuance in June 2005 of senior subordinated units when the senior subordinated units converted to common units in February 2006.

 

Income Taxes.   We provide income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. Income tax expense was $11.0 million and $11.1 million for the years ended December 31, 2007 and 2006, respectively.

 

Interest of Non-Controlling Partners in the Partnership’s Net Income.   The interest of non-controlling partners in the Partnership’s net income increased by $9.8 million to a loss of $3.2 million for the year ended December 31, 2007 compared to a loss of $13.0 million for the year ended December 31, 2006 due to the changes shown in the following summary (in thousands):

 

 

The general partner incentive distributions increased between these years due to an increase in the distribution amounts per unit and due to an increase in the number of common units outstanding

 

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

 

Gross Margin and Profit on Energy Trading Activities.   Midstream gross margin was $218.2 million for the year ended December 31, 2006 compared to $123.7 million for the year ended December 31, 2005, an increase of $94.6 million, or 76.5%. This increase was primarily due to acquisitions, increased system throughput and a favorable processing environment for natural gas and natural gas liquids.

 

The south Louisiana processing assets acquired in November 2005 contributed $56.1 million to Midstream gross margin growth in 2006. This amount was driven by the three largest processing plants, Eunice, Pelican and Sabine Pass, which contributed gross margin increases of $25.1 million, $11.4 million and $9.1 million, respectively. The Riverside fractionation facility and the Blue Water plant also contributed gross margin growth to the south Louisiana operations of $5.1 million and $3.7 million, respectively. Operational improvements and volume increases on the LIG system contributed margin growth of $12.5 million during 2006. Increased processing volumes at the Gibson and Plaquemine plants due to drilling successes by producers and increased unit margins due to favorable NGL markets accounted for a $9.5 million increase in gross margin. The Partnership acquired the north Texas gathering system from Chief in June 2006. This gathering system and related facilities contributed $11.7 million of gross margin during 2006. The NTP commenced operation during the second quarter of 2006 and contributed $8.0 million in gross margin. These gains were partially offset by volume and margin declines on our southern region assets. Decreased throughput on the south Texas systems contributed to an overall margin decrease in our southern region of $6.9 million.

Treating gross margin was $54.3 million for the year ended December 31, 2006 compared to $38.9 million for the year ended December 31, 2005, an increase of $15.5 million, or 39.7%. Treating plants in service increased from 112 plants at December 2005 to 160 plants (excluding 30 dew point control plants in service) at December 2006. The increase in the number of plants in service is primarily due to the acquisition of the amine treating assets from Hanover Compressor Company in February of 2006. New plants associated with the Hanover acquisition contributed $7.4 million in gross margin growth. The field services acquired from Hanover also contributed $1.0 million in gross margin for the year. Plant additions from inventory and expansion projects at existing plants contributed gross margin growth of $6.6 million and $0.5 million, respectively. The Seminole plant contributed $1.5 million of gross margin growth due to the recalculation of fees based on rate escalations set forth in the contract. The acquisition and installation of dew point control plants contributed an additional $0.7 million increase to gross margin.

 

Operating Expenses.   Operating expenses were $101.0 million for the year ended December 31, 2006 compared to $56.7 million for the year ended December 31, 2005, an increase of $44.3 million, or 78%. The increase in operating expenses related to asset acquisitions and the related engineering and technical service support needed for the asset growth. The Partnership’s Treating segment accounted for approximately $4.8 million of the increase with the remaining increase resulting from growth in its Midstream assets. Operating expenses included stock-based compensation expenses of $1.1 million and $0.4 million for the years ended December 31, 2006 and 2005, respectively.

 

General and Administrative Expenses.   General and administrative expenses were $47.7 million for the year ended December 31, 2006 compared to $34.1 million for the year ended December 31, 2005, an increase of $13.6 million, or 39.7%. Staffing and office infrastructure costs required for support of Midstream and Treating asset acquisitions accounted for the increase. General and administrative expenses included stock-based compensation expense of $7.4 million and $3.7 million for the year ended December 31, 2006 and 2005, respectively. The $3.8 million increase in stock-based compensation, determined in accordance with FAS 123R during 2006 and in accordance with APB25 in 2005, primarily relates to an increase in restricted stock and unit grants due to an increase in the pool of eligible participants.

 

Gain/Loss on Derivatives.   We had a gain on derivatives of $1.6 million for the year ended December 31, 2006 compared to a loss of $10.0 million for the year ended December 31, 2005. The gain in 2006 includes a gain of $2.9 million on storage financial transactions (including $0.7 million of realized gain), a gain of $0.7 million associated with basis swaps (including $0.4 million of realized gain), a gain of $1.5 million associated with derivatives for third-party on-system financial transactions (including $1.2 million of realized gains), and a gain of $0.1 million due to ineffectiveness in our hedged derivatives partially offset by a loss of $3.6 million on puts acquired in 2005 related to the acquisition of the South Louisiana Processing Assets. As of December 31, 2006, the fair value of the puts was $1.7 million. The loss in 2005 includes a $9.2 million loss on the puts related to the acquisition of the south Louisiana processing assets.

 

Gain/Loss on Sale of Property.   Assets sold during the year ended December 31, 2006 generated a net gain of $2.1 million as compared to a gain of $8.1 million during the year ended December 31, 2005. The gains in 2006 and 2005 primarily related to the sale of inactive gas processing facilities acquired as part of the South Louisiana Processing Assets and as part of the LIG acquisition.

 

Depreciation and Amortization.   Depreciation and amortization expenses were $82.8 million for the year ended December 31, 2006 compared to $36.1 million for the year ended December 31, 2005, an increase of $46.7 million, or 129.5%. An increase of $38.3 million in depreciation expense was associated with the acquisition of Midstream assets in 2005 and 2006 . The acquisition of the Treating assets and the increase in existing Treating assets in service contributed an increase of $5.0 million. The remaining increase of $3.4 million was a result of various other expansion projects, including the expansion of our corporate offices and related support facilities.

 

Interest Expense.   Interest expense was $51.1 million for the year ended December 31, 2006 compared to $15.3 million for the year ended December 31, 2005, an increase of $35.7 million. The increase relates primarily to an increase in debt outstanding as a result of acquisitions and other growth projects and higher interest rates between

years (weighted average rate of 6.9% in 2006 compared to 6.3% in 2005). Net interest expense consists of the following (in millions):

 

 

Other Income.   Other income was $1.8 million for the year ended December 31, 2006 compared to $0.4 million for the year ended December 31, 2005 because in 2006 we collected $1.6 million in excess of the carrying value of the Enron account receivable net of the allowance.

 

Income Taxes.   We provide income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. Income tax expense was $11.1 million for the year ended December 31, 2006 compared to $30.0 million for the year ended December 31, 2005, a decrease of $18.9 million. The decrease in the gain on issuance of units of the Partnership from $65.1 million during 2005 to $19.0 million during 2006 is the primary reason for the decrease in income taxes between years. Income after minority interest also decreased $5.7 million between years which also reduced the income tax expense between years.

 

Gain on Issuance of Units of the Partnership.   As a result of the Partnership issuing common units in June 2005 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $19.0 million. We recognized the $19.0 million gain associated with the unit issuance in February 2006 when the senior subordinated units converted to common units. We recognized a gain of $65.1 million during 2005 associated with the Partnership’s issuance of common units in November 2005.

 

Interest of Non-Controlling Partners in the Partnership’s Net Income.   The interest of non-controlling partners in the Partnership’s net income decreased by $17.7 million to a loss of $13.0 million for the year ended December 31, 2006 compared to income of $4.7 million for the year ended December 31, 2005 due to the changes shown in the following summary (in thousands):

 

 

The general partner incentive distributions increased between these years due to an increase in the distribution amounts per unit and due to an increase in the number of common units outstanding.

Cumulative Effect of Accounting Change.   We recorded a $0.2 million cumulative adjustment to recognize the required change in reporting stock-based compensation under FASB Statement No. 123R which was effective January 1, 2006. The cumulative effect of this change is reported in our income net of taxes and non-controlling partners’ interest.

 

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. See Note 2 of the Notes to Consolidated Financial Statements for further details on our accounting policies and a discussion of new accounting pronouncements.

 

Revenue Recognition and Commodity Risk Management.   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. It generally accrues one to two months of sales and the related gas purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

 

The Partnership utilizes extensive estimation procedures to determine the sales and cost of gas purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. It uses actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month or two following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as “actualization”. Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month’s accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. The Partnership believes that its accrual process for the one to two months of sales and purchases provides a reasonable estimate of such sales and purchases.

 

The Partnership engages in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and natural gas liquids. The Partnership manages its 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 its future commitments and significantly reduce its risk to the movement in natural gas prices.

 

The Partnership uses derivatives to hedge against changes in cash flows related to product prices and interest rates risks, as opposed to their use for trading purposes. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities requires that 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.

 

The Partnership conducts “off-system” gas marketing operations as a service to producers on systems that it does not own. The Partnership refers to these activities as part of energy trading activities. 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 revenue and cost of sales for these activities are shown net in the Statement of Operations.

 

We manage our price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas prices. However, we are subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives, and we use mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized in earnings as gain or loss on derivatives immediately. Net realized gains and losses on settled contracts are reported in profit on energy trading activities.

 

Sales of Securities by Subsidiaries.   We recognize gains and losses in the consolidated statements of operations resulting from subsidiary sales of additional equity interest, including the Partnership’s limited partnership units, to unrelated parties.

 

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.

 

Depreciation Expense and Cost Capitalization.   Our assets consist primarily of natural gas gathering pipelines, processing plants, transmission pipelines and natural gas treating plants owned by the Partnership. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

 

We generally compute depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The computation of

depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we may review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

 

financings have primarily consisted of borrowings under the Partnership’s bank credit facility, equity offerings and senior note issuances in the Partnership for 2007, 2006 and 2005 as follows (in millions):

 

 

Dividends to shareholders and distributions to non-controlling partners in the Partnership represent our primary use of cash in financing activities. Total cash distributions made during the last three years were as follows (in millions):

 

 

In order to reduce our interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility. Changes in drafts payable for 2007, 2006 and 2005 were as follows (in millions):

 

 

Working Capital Deficit.   We had a working capital deficit of $39.3 million as of December 31, 2007, primarily due to drafts payable of $28.9 million as of the same date. As discussed under “Cash Flows” above, in order to reduce our interest costs we do not borrow money to fund outstanding checks until they are presented to the bank. We borrow money under the Partnership’s $1.185 billion credit facility to fund checks as they are presented. As of December 31, 2007, we had approximately $323.7 million of available borrowing capacity under this facility.

 

Off-Balance Sheet Arrangements.   We had no off-balance sheet arrangements as of December 31, 2007 and 2006.

 

December 2007 Sale of Common Units.   On December 19, 2007, the Partnership issued 1,800,000 common units representing limited partner interests in the Partnership at a price of $33.28 per unit for net proceeds of $57.6 million. We made a general partner contribution of $1.2 million in connection with the issuance to maintain our 2% general partner interest.

 

March 2007 Sale of Senior Subordinated Series D Units.   On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests in a private offering for net proceeds of approximately $99.9 million. The senior subordinated series D units were issued at $25.80 per unit, which represented a discount of approximately 25% to the market value of common units on such date. The discount represented an underwriting discount plus the fact that the units will not receive a distribution nor be readily transferable for two years. We made a general partner contribution of $2.7 million in connection with this issuance to maintain our 2% general partner interest. The senior subordinated series D units will automatically convert into common units on March 23, 2009 at a ratio of one common unit for each senior subordinated series D unit, subject to adjustment depending on the achievement of financial metrics in the fourth quarter of 2008. The senior subordinated series D units are not entitled to distributions of available cash or allocations of net income/loss from the Partnership until March 23, 2009.

 

June 2006 Sale of Senior Subordinated Series C Units.   On June 29, 2006, the Partnership issued an aggregate of 12,829,650 senior subordinated series C units representing limited partner interests in a private equity offering

for net proceeds of $359.3 million. The senior subordinated series C units were issued at $28.06 per unit, which represented a discount of 25% to the market value of common units on such date. We purchased 6,414,830 of the senior subordinated series C units and made a general partner contribution of $9.0 million in connection with this issuance to maintain our 2% general partner interest. The senior subordinated series C units automatically converted to common units on February 16, 2008 at a ratio of one common unit for each senior subordinated series C unit. The senior subordinated series C units were not entitled to distributions of available cash until their conversion to common units.

 

November 2005 Sale of Senior Subordinated B Units.   On November 1, 2005, the Partnership issued 2,850,165 senior subordinated series B units in a private placement for a purchase price of $36.84 per unit. It received net proceeds of approximately $107.1 million, including our general partner contribution of $2.1 million and expenses associated with the sale. The senior subordinated series B units automatically converted into common units on November 14, 2005 at a ratio of one common unit for each senior subordinated series B unit and were not entitled to distributions paid on November 14, 2005.

 

November 2005 Public Offering.   In November 2005, the Partnership issued 3,731,050 common units to the public at a purchase price of $33.25 per unit. The offering resulted in net proceeds to the Partnership of $120.9 million, including our general partner contribution of $2.5 million and net of expenses associated with the offering.

 

June 2005 Sale of Senior Subordinated Units.   In June 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including our general partner contribution of $1.1 million. These units automatically converted to common units on a one-for-one basis on February 24, 2006. The senior subordinated units received no distributions until their conversion to common units in February 2006.

 

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

 

 

Given the Partnership’s objective of growth through large capital expansions and acquisitions, it anticipates that it will continue to invest significant amounts of capital to grow and to build and acquire assets. The Partnership actively considers a variety of assets for potential development or acquisition. The Partnership is continuing its build-out of its north Texas facilities during 2008, including a 29-mile natural gas gathering pipeline in north Johnson County, Texas, which is under construction and scheduled to be completed in the second quarter of 2008.

 

The Partnership believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.61 per unit and to fund a portion of anticipated capital expenditures through December 31, 2008. Total capital expenditures are budgeted to be approximately $250 million in 2008 including approximately $23 million for maintenance capital expenditures. In 2008, it is possible that not all of the planned projects will be commenced or completed. The Partnership expects to fund maintenance capital expenditures from operating cash flows. It expects to fund the growth capital expenditures from the proceeds of borrowings under the bank credit facility discussed below, and with other debt and equity sources. Our ability to pay dividends to our stockholders and to fund planned capital expenditures and to make acquisitions will depend upon the Partnership’s future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond our control.

Total Contractual Cash Obligations.   A summary of the Partnership’s total contractual cash obligations as of December 31, 2007, is as follows:

 

 

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

 

The Partnership’s interest payable under its Credit Facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates which will vary from time to time. Based on balances outstanding and rates in effect at December 31, 2007, annual interest payments would be $49.8 million. The interest amounts also exclude estimates of the effect of our interest rate swap contracts.

 

The unconditional purchase obligations for 2008 relate to purchase commitments for equipment. The Partnership has also committed to contract for 150,000 MMBtu/day of firm transportation capacity on a pipeline that is expected to be in service in the fourth quarter of 2008. This commitment is not reflected in the summary above since the pipeline is not yet constructed. Under the transportation commitment agreement with Boardwalk Pipeline Partners, L.P., we will be obligated to issue an $80.0 million letter of credit if demanded by Boardwalk prior to the commencement of operation of this new pipeline.

 

 

Credit Facility.   In September 2007, the Partnership increased borrowing capacity under the bank credit facility to $1.185 billion. The bank credit facility matures in June 2011. As of December 31, 2007, $861.3 million was outstanding under the bank credit facility, including $127.3 million of letters of credit, leaving approximately $323.7 million available for future borrowing.

 

Obligations under the bank credit facility are secured by first priority liens on all of the Partnership’s material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in certain of its subsidiaries, and rank pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by certain of the Partnership’s subsidiaries. The Partnership

may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

 

Under the amended credit agreement, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on the Partnership’s leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees ranging from 0.20% to 0.375% on the unused amount of the credit facilities.

 

The credit agreement prohibits the Partnership from declaring distributions to unit-holders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. In addition, the bank credit facility contains various covenants that, among other restrictions, limit the Partnership’s ability to:

 

 

In April 2007, the Partnership amended its bank credit facility, effective as of March 28, 2007, to increase the maximum permitted leverage ratio for the fiscal quarter ending September 30, 2007 and each fiscal quarter thereafter. The maximum leverage ratio (total funded debt to consolidated pro forma earnings before interest, taxes, depreciation and amortization) is as follows (provided, however, that during an acquisition period as defined in the bank credit facility, the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable ratio set forth below):

 

 

Additionally, the bank credit facility now provides that (i) if the Partnership or its subsidiaries incur unsecured note indebtedness, the leverage ratio will shift to a two-tiered structure and (ii) during periods where the Partnership has outstanding unsecured note indebtedness, the Partnership’s leverage ratio cannot exceed 5.50 to 1.00 and the Partnership’s senior leverage ratio cannot exceed 4.50 to 1.00. The other material terms and conditions of the credit facility remained unchanged.

 

The bank credit facility contains a covenant requiring us to maintain a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four-quarter basis, equal to 3.0 to 1.0.

 

Each of the following will be an event of default under the bank credit facility:

 

 

 

The Partnership is subject to interest rate risk on its credit facility and has entered into interest rate swaps to reduce this risk. See Note (5) to the financial statements for a discussion of interest rate swaps.

 

Senior Secured Notes.   The Partnership entered into a master shelf agreement with an institutional lender in 2003 that was amended in subsequent years to increase availability under the agreement, pursuant to which it issued the following senior secured notes (dollars in thousands):

 

 

In April 2007, the Partnership amended the senior note agreement, effective as of March 30, 2007, to (i) provide that if the Partnership’s leverage ratio at the end of any fiscal quarter exceeds certain limitations, the Partnership will pay the holders of the senior secured notes an excess leverage fee based on the daily average outstanding principal balance of the senior secured notes during such fiscal quarter multiplied by certain percentages set forth in the senior note agreement; (ii) increase the rate of interest on each senior secured note by 0.25% if, at any given time during an acquisition period (as defined in the senior note agreement), the leverage ratio exceeds 5.25 to 1.00; (iii) cause the leverage ratio to shift to a two-tiered structure if the Partnership or its subsidiaries incur unsecured note indebtedness; and (iv) limit the Partnership’s leverage ratio to 5.25 to 1.00 and the Partnership’s senior leverage ratio to 4.25 to 1.00 during periods where the Partnership has outstanding unsecured note indebtedness. The other material items and conditions of the senior note agreement remained unchanged.

 

These notes represent senior secured obligations of the Partnership and will rank at least pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with obligations of the Partnership under the credit facility, by first priority liens on all of its material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all its equity interests in certain of its subsidiaries. The senior secured notes are guaranteed by certain of the Partnership’s subsidiaries.

 

The $40.0 million of senior secured notes issued in 2003 are redeemable, at the Partnership’s option and subject to certain notice requirements, at a purchase price equal to 100% of the principal amount together with accrued interest, plus a make-whole amount determined in accordance with the master shelf agreement. The senior secured notes issued 2004, 2005 and 2006 provide for a call premium of 103.5% of par beginning three years after issuance at rates declining from 103.5% to 100.0%. The notes are not callable prior to three years after issuance. During 2008 the notes may also incur an additional fee each quarter of 0.15% per annum on the outstanding

borrowings if the Partnership’s leverage ratio, as defined in the agreement, exceeds certain levels during such quarterly period.

 

The master shelf agreement relating to the notes contains substantially the same covenants and events of default as the bank credit facility.

 

The Partnership was in compliance with all debt covenants at December 31, 2007 and 2006 and expects to be in compliance with debt covenants for the next twelve months.

 

Intercreditor and Collateral Agency Agreement.   In connection with the execution of the master shelf agreement, the lenders under the bank credit facility and the purchasers of the senior secured notes have entered into an Intercreditor and Collateral Agency Agreement, which has been acknowledged and agreed to by the Partnership and its subsidiaries. This agreement appointed Bank of America, N.A. to act as collateral agent and authorized Bank of America to execute various security documents on behalf of the lenders under the bank credit facility and the purchasers of the senior secured notes. This agreement specifies various rights and obligations of lenders under the bank credit facility, holders of senior secured notes and the other parties thereto in respect of the collateral securing the Partnership’s obligations under the bank credit facility and the master shelf agreement.

 

Credit Risk

 

We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, the Partnership’s purchase and resale of gas and NGLs 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 its overall profitability.

 

Inflation

 

Inflation in the United States has been relatively low in recent years in economy as a whole. The midstream natural gas industry has experienced an increase in labor and material costs during the year, although these increases did not have a material impact on our results of operations for the periods presented. 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.

 

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.”

 

Contingencies

 

On November 15, 2007, Crosstex CCNG received a demand letter from Denbury asserting a claim for breach of contract and seeking payment of approximately $11.4 million in damages. The claim arises from a contract under which Crosstex CCNG processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex CCNG breached the contract by failing to build a processing plant of a certain size and design, resulting in Crosstex CCNG’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex CCNG failed to provide specific notices required under the contract. On December 4, 2007 and again on February 14, 2008, Denbury sent Crosstex CCNG letters demanding that its claim be arbitrated pursuant to an arbitration provision in the contract. Denbury subsequently requested that the parties attempt to mediate the matter before any arbitration proceeding is initiated. Although it is not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse effect on our consolidated results of operations or financial position.

Recent Accounting Pronouncements

 

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” which we adopted effective January 1, 2007. FIN 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The adoption of FIN 48 had no material impact to our financial statements. At December 31, 2007, we have no material assets, liabilities or accrued interest associated with uncertain tax positions. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. At December 31, 2007, tax years 2001 through 2007 remain subject to examination by the Internal Revenue Service and applicable states. We do not expect any material change in the balance of our unrecognized tax benefits over the next twelve months.

 

On September 13, 2006, the Securities Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (SAB 108), which establishes an approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related disclosures. SAB 108 requires the use of a balance sheet and an income statement approach to evaluate whether either of these approaches results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. We adopted SAB 108 effective October 1, 2006 with no material impact on its financial statements.

 

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. While SFAS 157 does not add any new fair value measurements, it is intended to increase consistency and comparability of such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

 

In February 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment to FASB Statement No. 115” (SFAS 159) permits entities to choose to measure many financial assets and financial liabilities at fair value. Changes in the fair value on items for which the fair value option has been elected are recognized in earnings each reporting period. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes elected for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 will have no material impact on our financial statements.

 

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (SFAS 141R) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160.

 

Disclosure Regarding Forward-Looking Statements

 

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, that

are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included in this Form 10-K constitute forward-looking statements, including but not limited to statements identified by the words “may,” “will,” “should,” “plan,” “predict,” “anticipate,” “believe,” “intend,” “estimate” and “expect” and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Form 10-K, the risk factors set forth in “Item 1A. Risk Factors” may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

 

sold under either basis, which leaves it with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

 

The Partnership also has hedges in place covering liquids volumes it expects to receive under percent of proceeds contracts. At its south Louisiana plants, it has hedged approximately 80% of exposure through May 2008 and at various levels less than 50% from June 2008 through the first quarter of 2009. Other Partnership assets, have hedged approximately 69% of their exposure through June 2008 and at various levels less than 50% from July 2008 through the first quarter of 2009.

 

The Partnership has commodity price risk associated with its processed volumes of natural gas. The Partnership currently processes gas under four main types of contractual arrangements:

 

1.  Keep-whole contracts:   Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. The Partnership controls its risk on our current keep-whole contracts through its ability to bypass processing when it is not profitable.

 

2.  Percent of proceeds contracts:   Under these contracts, The Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, its margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of proceeds contracts, but decline during periods of low NGL prices.

 

3.  Theoretical processing contracts:   Under these contracts, the Partnership stipulates with the producer the assumptions under which it will assume processing economics for settlement purposes, independent of actual processing results or whether the stream was actually processed. These contracts tend to have an inverse result to the keep-whole contracts, with better margins as processing economics worsen.

 

4.  Fee-based contracts:   Under these contracts the Partnership has no commodity price exposure, and is paid a fixed fee per unit of volume that is treated or conditioned.

 

The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a Risk Management Committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its Risk Management Committee.

 

The use of financial instruments may expose the Partnership 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) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

 

As of December 31, 2007, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $9.3 million. The aggregate effect of a hypothetical 10% increase in gas and NGLs prices would result in an increase of approximately $5.9 million in the net fair value liability of these contracts as of December 31, 2007.