Item 1.
Business
General
Crosstex Energy, Inc. is a Delaware corporation, formed in April 2000. We completed our initial public offering in January 2004. Our shares of common stock are listed on the NASDAQ National Market under the symbol “XTXI”. Our executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.crosstexenergy.com. In the Investor Information section of our web site, we post the following filings as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual report on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our web site are available free of charge. In this report, the terms “Crosstex Energy, Inc.” as well as the terms “our,” “we,” and “us,” or like terms, are sometimes used as references to Crosstex Energy, Inc. and its consolidated subsidiaries. References in this report to “Crosstex Energy, L.P.,” the “Partnership,” “CELP,” or like terms refer to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. and its consolidated subsidiaries.
CROSSTEX ENERGY, INC.
Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids. These partnership interests consist of the following:
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2,999,000 common units and 7,001,000 subordinated units, representing a 38% limited partner interest in the Partnership; and
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100% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.
Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.
The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 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 $0.51 per unit for the quarter ended December 31, 2005. As a result, our distributions from the Partnership pursuant to our ownership of our 10,000,000 common and subordinated units have increased from $2.5 million for the quarter ended March 31, 2003 to $5.1 million for the quarter ended December 31, 2005; our distributions pursuant to our 2% general partner interest have increased from $74,000 to $4.3 million; and our distributions pursuant to our incentive distribution rights have increased from nothing to approximately $4.0 million. As a result, we have increased our dividend from $0.30 per share for the quarter ended March 31, 2004 (the first dividend payout after our initial public offering) to $0.56 per share for the quarter ended December 31, 2005.
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:
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federal income taxes, which we are required to pay because we are taxed as a corporation;
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the expenses of being a public company;
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other general and administrative expenses;
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capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s 2.0% general partner interest; and
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reserves our board of directors believes prudent to maintain.
If the Partnership is 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.
Our ability to pay dividends is limited by the Delaware General Corporation Law, which provides that a corporation may only pay dividends out of existing “surplus,” which is defined as the amount by which a corporation’s net assets exceeds its stated capital. While our ownership of the general partner and the common and subordinated units of the Partnership are included in our calculation of net assets, the value of these assets may decline to a level where we have no “surplus,” this prohibiting us from paying dividends under Delaware law.
The Partnership’s strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas; improving the profitability of its assets by increasing their utilization while controlling costs; 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 $530,000, and we would receive $365,000, or 69% of that increase.
So long as we own the general partner, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing natural gas liquids, or 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:
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the nature of some or all of the target’s assets or income might affect the Partnership’s ability to be taxed as a partnership for federal income tax purposes;
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the board of directors of Crosstex Energy GP, LLC may conclude that some or all of the target assets are not a good strategic opportunity for the Partnership; or
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the seller may desire equity, rather than cash, as consideration and may not want to accept the Partnership’s units as consideration.
We have no present intention of engaging in additional operations or pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement, although we may decide to pursue them in the future, either alone or in combination with the Partnership. In the event that we pursue the types of opportunities that we are permitted to pursue under the omnibus agreement, our board of directors, in its sole discretion, may retain all, or a portion of, the cash distributions we receive on our partnership interests in the Partnership to finance all, or a portion of, such transactions, which may reduce or eliminate dividends paid to our stockholders.
CROSSTEX ENERGY, L.P.
Crosstex Energy, L.P., is 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 natural gas liquids into purity products and markets those products for a fee, transports natural gas and ultimately provides an aggregated supply of 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 and thereby generates gross margins based on the difference between the purchase and resale prices. 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.
The Partnership has two operating segments, Midstream and Treating. The Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and natural gas liquids, while the Treating division focuses on the removal of impurities from natural gas to meet pipeline quality specifications. On November 1, 2005, the Partnership acquired El Paso Corporation’s natural gas processing and liquids business in south Louisiana, which we refer to as the El Paso Acquisition, significantly expanding its midstream presence in that area. Following this acquisition, the primary midstream assets include approximately 5,000 miles of natural gas gathering and transmission pipelines, nine 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 Partnership’s processing plants remove NGLs from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso- and normal butanes and natural gasoline. The primary treating assets include approximately 190 natural gas treating 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 13 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
Business Strategy
The Partnership’s strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation, and marketing of natural gas and NGLs; improving the profitability of its assets by increasing their utilization while controlling costs; accomplishing economies of scale through new construction or expansion in core operating areas; and maintaining financial flexibility to take advantage of opportunities. The Partnership will also build new assets in response to producer and market needs, such as the North Texas Pipeline project as discussed below. We believe the expanded scope of the Partnership’s operations, combined with a continued high level of drilling in its principal geographic areas, should present opportunities for continued expansion in its 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 the strategy include the following:
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Pursuing accretive acquisitions. The Partnership intends to use its acquisition and integration experience to continue to make strategic acquisitions of midstream assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset. It pursues acquisitions that it believes will add to existing core areas in order to capitalize on its existing infrastructure, personnel, and producer and consumer relationships. For example, the Partnership believes the El Paso Acquisition complements its existing asset base in Louisiana and provides opportunities for asset optimization and cost-saving opportunities. The Partnership also examines opportunities to establish new core areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. The Partnership plans to establish new core areas primarily through the acquisition or development of key assets that will serve as a platform for further growth both through additional acquisitions and the construction of new assets. The Partnership established two new core areas through the acquisition and consolidation of its south Texas assets in 2000 through 2003, and the acquisition of the LIG Pipeline Company and its subsidiaries, which we collectively refer to as LIG, in 2004. The Partnership is now working to consolidate the El Paso Acquisition with LIG to develop operating synergies.
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Improving existing system profitability. After the Partnership acquires or constructs a new system, it begins an aggressive effort to market services directly to both producers and end users in order to connect new supplies of natural gas, improve margins, and more fully utilize the system’s capacity. As part of this process, the Partnership focuses on providing a full range of services to small and medium size independent producers and end users, including supply aggregation, transportation and hedging which the Partnership believes provides a competitive advantage when competing for sources of natural gas supply. Since treating services are not provided by many competitors, the Partnership has an additional advantage in competing for new supply when gas requires treating to meet pipeline specifications. Additionally, the Partnership emphasizes increasing the percentage of natural gas sales directly to end users, such as industrial and utility consumers, in an effort to increase operating margins.
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Undertaking construction and expansion opportunities (“organic growth”). The Partnership leverages its existing infrastructure and producer and customer relationships by constructing and expanding systems to meet new or increased demand for gathering, transmission, treating, processing and marketing services. These projects include expansion of existing systems and construction of new facilities, which has driven the growth of the Treating division in recent years. In 2005, the Partnership began construction on a new 143-mile pipeline to transport gas from an area near Fort Worth, Texas, where recent drilling activity in the Barnett Shale formation has expanded production beyond the existing infrastructure capability. The Partnership refers to this project as the North Texas Pipeline project and expects that it will commence operations in the first quarter of 2006. Once completed, the pipeline will allow curtailed gas to flow to markets that are currently not available to some key Barnett Shale producers. The Partnership is currently evaluating several similar projects in Texas and Louisiana.
Recent Acquisitions and Expansion
El Paso Corporation processing and liquids business. On November 1, 2005 the Partnership acquired the south Louisiana processing and liquids business of El Paso Corporation for $481.0 million. The acquired assets
include 2.3 Bcf/d of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage, and approximately 400 miles of liquids transport lines. CELP believes the El Paso Acquisition provides several key strategic benefits, including:
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the opportunity to participate in the growing development of deepwater Gulf of Mexico reserves;
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the opportunity to establish a significant presence in the natural gas liquids marketing business;
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the opportunity to realize operating efficiencies with the existing asset base in Louisiana, including the ability to shift processing from some of the plants acquired with the LIG system to plants acquired from El Paso that have additional capacity, reducing overall operating costs and freeing certain LIG assets to be redeployed to underserved markets; and
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a larger business platform from which it can grow the midstream operations.
Graco Operations. In January 2005, the Partnership acquired all of the assets of Graco Operations for $9.26 million. The acquisition added approximately 25 treating plants and related inventory.
Cardinal Gas Services. The Partnership acquired the treating and gas processing operations of Cardinal Gas Services as of May 1, 2005 for $6.7 million. The acquisition added nine treating plants and 19 dewpoint control plants. This acquisition allowed the Partnership to extend its service capabilities into the dewpoint suppression business.
North Texas Pipeline Project. In 2005, the Partnership began construction on a new 143-mile pipeline and associated gathering lines from an area near Fort Worth, Texas to a point near Paris, Texas. This project connects production from the Barnett Shale to markets in north Texas and to markets accessed by the NGPL pipeline and other pipelines the Partnership connects with. Drilling success in the Barnett Shale formation in the area has expanded production beyond the capacity of the existing pipeline infrastructure. Capital costs to construct the pipeline and associated facilities are estimated to be approximately $115 million, with completion estimated in the first quarter of 2006. The pipeline will allow contracted gas to flow to markets that are currently not available to some key Barnett Shale producers.
Hanover Acquisition. On February 1, 2006, the Partnership acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.5 million. After this acquisition the Partnership has approximately 150 treating plants in operation and a total fleet of approximately 190 units.
Other Developments
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 $1.1 million capital contribution and after expenses associated with the sale. The senior subordinated units were issued at $33.44 per unit, which represented a discount of 13.7% to the market value of common units on such date, and automatically converted into common units on a one-for-one basis on February 24, 2006. The senior subordinated units were not entitled to distributions of available cash until they 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 $2.1 million capital contribution and after expenses associated with the sale. The Senior Subordinated Series B Units automatically converted into common units on November 14, 2005 on a one-for-one basis. The Senior Subordinated Series B Units were not entitled to distributions paid on November 14, 2005. The net proceeds were used to fund a portion of the El Paso Acquisition.
November 2005 Public Offering. In November and December 2005, CELP 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 approximately $120.9 million, including our $2.5 million capital contribution and after expenses associated with the offering. The net proceeds were used to fund a portion of the El Paso Acquisition.
Bank Credit Facility. On November 1, 2005, the Partnership amended its bank credit facility to, among other things, provide for revolving credit borrowings up to a maximum principal amount of $750 million and the issuance
of letters of credit in the aggregate face amount of up to $300 million, which letters of credit reduce the credit available for revolving credit borrowings. The bank credit agreement includes procedures for additional financial institutions selected by the Partnership to become lenders under the agreement, or for any existing lender to increase its commitment in an amount approved by the Partnership and the lender, subject to a maximum of $300 million for all such increases in commitments of new or existing lenders. The maturity date was also extended to November 2010.
Senior Secured Notes. In November 2005, the Partnership completed a private placement of $85 million of senior secured notes pursuant to the master shelf agreement with institutional lenders with an interest rate of 6.23% and a maturity of ten years. The Partnership used the net proceeds from this private placement to reduce the balance of its bank loan and credit facility. As of December 31, 2005, borrowings under the master shelf agreement totaled $200.0 million.
Midstream Segment
Gathering, Processing and Transmission. CELP’s primary Midstream assets include systems located primarily along the Texas Gulf Coast and in south-central Mississippi and in Louisiana, which, in the aggregate, consist of approximately 5,000 miles of pipeline, nine processing plants and four fractionators and contributed approximately 76% and 77% of its gross margin in 2005 and 2004, respectively.
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El Paso Acquisition. On November 1, 2005, CELP acquired El Paso Corporation’s natural gas processing and liquids business in south Louisiana. The assets acquired include a total of 2.3 Bcf/d of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines.
The primary facilities and other assets acquired consist of:
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Eunice Processing Plant and Fractionation Facility. The Eunice facilities are located near Eunice, Louisiana. The Eunice processing plant has a capacity of 1.2 Bcf/d and processed approximately 787 MMcf/d of natural gas for the nine months ended September 30, 2005 (prior to the acquisition and prior to the full impact of Hurricanes Rita and Katrina). In November and December 2005 (after the acquisition and the impacts of the hurricanes), the plant processed approximately 934 MMcf/d. The plant is connected to onshore, continental shelf and deepwater gas production and has downstream connections to the ANR Pipeline, Florida Gas Transmission and Texas Gas Transmission pipeline systems. The Eunice fractionation facility has a capacity of 36,000 barrels per day of liquid products. This facility also has 190,000 barrels of above-ground storage capacity. The fractionation facility produces ethane, propane, iso-butane, normal butane and natural gasoline for customers such as Westlake, Econogas, Dufour, Ferrell Gas, Hercules and Marathon. The fractionation facility is directly connected to the Southeast propane market and pipelines to the Anse La Butte storage facility. In connection with the acquisition of this facility, CELP also acquired a three-year storage agreement with the Anse La Butte facility.
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Pelican Processing Plant. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. For the nine months ended September 30, 2005 (prior to the acquisition and prior to the full impact of Hurricanes Rita and Katrina), the plant processed approximately 311 MMcf/d. In November and December 2005 (after the acquisition and the impacts of the hurricanes), the plant processed approximately 226 MMcf/d. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline.
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Sabine Pass Processing Plant. The Sabine Pas processing plant is located 15 miles east of the Sabine River at Johnson’s Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. The Sabine Pass plant is connected to continental shelf and deepwater gas production with downstream connections to Florida Gas Transmission, Tennessee Gas Pipeline and Transco. For the nine months ended September 30, 2005 (prior to the acquisition and prior
to the full impact of Hurricanes Rita and Katrina), this facility processed approximately 235 MMcf/d. In November and December 2005 (after the acquisition and the impacts of the hurricanes), the plant processed approximately 125 MMcf/d.
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Blue Water Gas Processing Plant. CELP acquired a 23.85% interest in the Blue Water gas processing plant, which represents a net processing capacity to the acquired interest of 186 MMcf/d. Approximately 52 MMcf/d of the net capacity was being used in the nine months ended September 30, 2005 (prior to the acquisition and prior to the full impact of Hurricanes Rita and Katrina). In November and December 2005 (after the acquisition and the impacts of the hurricanes), approximately 21 MMcf/d was processed net to the interest. The Blue Water plant is located near Crowley, Louisiana and is operated by ExxonMobil. The Blue Water facility is connected to continental shelf and deepwater production volumes through the Blue Water pipeline system. Downstream connections from this plant include the Tennessee Gas Pipeline and Columbia Gulf. The facility also performs LNG conditioning services for the Excelerate Energy LNG tanker unloading facility.
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Riverside Fractionation Plant. The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of 28,000 to 30,000 barrels per day of liquids products and fractionates liquids delivered by the Cajun Sibon pipeline system from the Pelican, Blue Water and Cow Island plants or by truck. The Riverside facility has above-ground storage capacity of approximately 102,000 barrels.
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Napoleonville Storage Facility. The Napoleonville natural gas liquid storage facility is connected to the Riverside facility and has a total capacity of 2.4 million barrels of underground storage.
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Cajun Sibon Pipeline System. The Cajun Sibon pipeline system consists of 400 miles of 6-inch and 8-inch pipelines with a system capacity of 28,000 barrels per day. The pipeline transports raw make from the Pelican Complex and the Blue Water Plant to either the Riverside Fractionator or the Napoleonville storage facility. Alternate deliveries can be made to the Eunice Plant.
Hurricane Katrina struck the Coast of Louisiana and Mississippi in August 2005, after causing damage to Gulf of Mexico production and transmission facilities. Hurricane Rita struck the Gulf Coast of Texas and Louisiana the last week of September 2005, also damaging production and transmission infrastructure and causing minor damage to the Sabine Pass processing plant. El Paso bore the costs of the repairs to this plant, which is now complete, and the facility recommenced operations in December 2005. All other facilities were operational after minor clean-up from the storms, although throughput has not yet returned to levels the Partnership anticipated prior to the acquisition, as the offshore pipelines supplying natural gas to the facilities have experienced difficulties in making necessary infrastructure repairs. Those repairs are expected to be completed over the course of the first and second quarters of 2006 and volumes to be substantially restored after that.
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LIG System. CELP acquired the LIG system on April 1, 2004. The LIG system is the largest intrastate pipeline system in Louisiana, consisting of 2,000 miles of gathering and transmission pipeline, and had an average throughput of approximately 613,000 MMBtu/d for the year ended December 31, 2005. The system also includes two operating processing plants with an average throughput of 300,000 MMBtu/d for the year ended December 31, 2005. The system has access to both rich and lean gas supplies. These supplies reach from north Louisiana to new offshore production in southeast Louisiana. LIG has a variety of transportation and industrial sales customers, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.
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South Texas System. CELP has assembled a highly-integrated south Texas system comprised of approximately 1,400-miles of intrastate gathering and transmission pipelines and a processing plant with a processing capacity of approximately 150,000 mcf/d. This system was built through a number of acquisitions and follow-on organic projects. The acquisitions were the Gulf Coast system, the Corpus Christi
system, the Gregory gathering system and processing plant, the Hallmark system, and the Vanderbilt system. Average throughput on the system for the year ended December 31, 2005 was approximately 517,000 MMBtu/d. Average throughput in the processing plant was approximately 95,000 MMBtu/d for that period. The system gathers gas from major production areas in the Texas Gulf coast and delivers gas to the industrial markets, power plants, other pipelines, and gas distribution companies in the region from Corpus Christi to the Houston area.
Other midstream assets and activities:
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Mississippi Pipeline System. This 603-mile system in south Mississippi gathers wellhead supply in the region and sells it through direct market connections to utilities and industrial end-users. Average throughput on the system was approximately 83,000 MMBtu/d for the year ended December 31, 2005.
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Arkoma Gathering System. This 140-mile low-pressure gathering system in southeastern Oklahoma delivers gathered gas into a mainline transmission system. For the year ended December 31, 2005, throughput on the system averaged approximately 23,000 MMBtu/d.
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Other. Other midstream assets consist of a variety of gathering lines and a processing plant with a processing capacity of approximately 65,000 Mcf/d. Total volumes gathered and resold were approximately 65,000 MMBtu/d for the year ended December 31, 2005. Total volumes processed were approximately 23,000 MMBtu/d in the period.
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Off-System Services. CELP offers natural gas marketing services on behalf of producers for natural gas that does not move on its assets. It markets this gas on a number of interstate and intrastate pipelines. These volumes averaged approximately 181,000 MMBtu/d in 2005.
Treating Segment
CELP operates treating plants which remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications. The treating division contributed approximately 24% and 23% of the Partnership’s gross margin in 2005 and 2004, respectively. During 2005 the Partnership spent $16.0 million in two separate acquisitions to acquire 35 treating plants, 19 dewpoint control plants and related inventory. The treating business has grown from 74 plants in operation at December 31, 2004 to 112 plants in operation at December 31, 2005. In February 2006, CELP acquired the amine treating assets of a subsidiary of Hanover Compression Company, increasing total plants in operation to approximately 150 and its total fleet of treating plants to approximately 190.
CELP believes it has the largest gas treating operation in the Texas and Louisiana Gulf Coast. The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced to transportation systems to ensure that it meets pipeline quality specifications. Natural gas from certain formations in the Texas Gulf Coast, as well as other locations, is high in carbon dioxide. Many of the Partnership’s active plants are treating gas from the Wilcox and Edwards formations in the Texas Gulf Coast, both of which are deeper formations that are high in carbon dioxide. 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 charges a fixed monthly fee.
CELP 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 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 $0.57 for each Mcf of carbon dioxide returned. The plant also receives 50% of the NGLs produced by the plant.
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. We believe 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. CELP 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 in the Texas Gulf Coast is high in carbon dioxide. Most treating plants and transmission pipelines are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems to ensure that it meets pipeline quality specifications.
Natural gas processing and fractionation. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural
gas and a mixed NGL stream, as well as the removal of contaminants. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.
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 CELP purchases natural gas, it normally establishes a margin by selling natural gas for physical delivery to third-party users. CELP 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, CELP 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. CELP’s policy is not to acquire and hold natural gas futures 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. CELP faces strong competition in acquiring new natural gas supplies. CELP’s competitors in obtaining additional gas supplies and in treating new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on 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 CELP’s competitors offer more services or have greater financial resources and access to larger natural gas supplies than it does. CELP’s competition will likely differ in different geographic areas.
The gas treating operations face competition from manufacturers of new treating and dewpoint control plants and from a small number of regional operators that provide plants and operations similar to the Partnership. CELP also faces competition from vendors of used equipment that occasionally operate plants for producers. In addition, CELP routinely loses business to gas gatherers who have underutilized treating or processing capacity and can take the producers’ gas without requiring wellhead treating. CELP 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, CELP 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 CELP.
CELP 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 CELP’s competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. CELP’s competition differs by region and by the nature of the business or the project involved.
Natural Gas Supply
CELP’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, CELP evaluates well and reservoir data furnished by producers 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, CELP believes
that there should be adequate natural gas supply to recoup the investment with an adequate rate of return. CELP does not routinely obtain independent evaluations of reserves dedicated to its systems due to the cost and relatively limited benefit of such evaluations. Accordingly, CELP does not have estimates of total reserves dedicated to its systems or the anticipated life of such producing reserves.
Credit Risk and Significant Customers
CELP is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the purchase and resale of gas exposes CELP 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 CELP’s overall profitability.
During the year ended December 31, 2005, CELP had one customer that individually accounted for approximately 10.6% 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 our results of operations.
Regulation
Regulation by FERC of Interstate Natural Gas Pipelines. CELP does not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission (“FERC”) does not directly regulate its operations under the National Gas Act (“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:
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the certification and construction of new facilities;
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the extension or abandonment of services and facilities;
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the maintenance of accounts and records;
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the acquisition and disposition of facilities;
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maximum rates payable for certain services;
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the initiation and discontinuation of services; and
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various other matters.
In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines’ rates and rules and policies that may affect rights of access to natural gas transportation capacity. The Partnership’s intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but the rates, terms and conditions of service under which it transports natural gas in their pipeline systems in interstate commerce are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“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 Louisiana and Mississippi pipeline systems are each subject to review in 2006.
Intrastate Pipeline Regulation. CELP’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, principally the Texas Railroad Commission, or TRRC, and the Louisiana Department of Natural Resources Office of Conservation. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.
The Partnership’s operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. Once set, the rates they charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against the Partnership or whether the TRRC will change its regulation of these rates.
CELP owns a private line in New Mexico that is used to serve one customer, of which approximately one mile is regulated by the New Mexico Public Regulation Commission. Similarly, a twelve-mile section of CELP’s Mississippi gathering system is regulated by the Mississippi Oil and Gas Board as it transports gas not owned by them for a fee. The Arkoma gathering system in Oklahoma is regulated by the Oklahoma Corporation Commission. Similarly, gathering systems owned by the Partnership in Alabama are subject to regulation by the Alabama State Oil and Gas Board. CELP’s LIG intrastate system is regulated by the Louisiana Department of Natural Resources Office of Conservation.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. CELP 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. 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. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
The Partnership is subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting CELP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint based regulation that generally allows 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. CELP’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Their 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.
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
CELP’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. CELP’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 our overall costs of doing business, including cost of planning, constructing, and operating plants, pipelines, and other facilities. Included in CELP’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 CELP currently holds all material governmental approvals required to operate our major facilities, we are currently evaluating and updating permits for certain of our facilities specifically including those obtained in recent acquisitions. As part of the regular overall evaluation of our operations, CELP has implemented procedures and are 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 CELP’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 CELP’s possible future operations, and we cannot assure you that CELP 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, CELP may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject CELP 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. CELP 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 environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of “hazardous substance” into the environment. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response
to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of future, ordinary operations, CELP may generate wastes that may fall within the definition of a “hazardous substance.” CELP 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.
CELP 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 CELP 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 CELP’s capital expenditures or plant operating expenses.
CELP 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 us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom CELP 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, CELP 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 the El Paso Corporation 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, CELP 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. The estimated remediation costs are expected to be approximately $0.3 million. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to CELP’s ownership, these costs were accrued as part of the purchase price.
CELP 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. CELP does not expect to incur any material liability in connection with the remediation associated with these sites.
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. CELP 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, CELP’s processing and fractionating plants, pipelines, and storage facilities or any of its future assets that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. Such requirements, if applicable to CELP’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 CELP’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 our 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. CELP 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 our results of operations.
Employee Safety. CELP 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. CELP 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. CELP’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 CELP’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. CELP 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 our results of operations or financial positions.
Employees
As of December 31, 2005, the Partnership had approximately 496 full-time employees. Approximately 218 of the employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. CELP is not party to any collective bargaining agreements, and has not had any significant labor disputes in the past. We believe that CELP has good relations with its employees.
Item 1A.
Item 1A.
Risk Factors
The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are described below, may also impact our results of operations. If any of the following risks occurs, our business, financial condition or results of operations could be affected materially and adversely. In that case, the trading price of our common stock could decline. These risk factors should be read in conjunction with the other detailed information concerning us set forth in our accompanying financial statements and notes and contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included herein.
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:
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the amount of natural gas transported in its gathering and transmission pipelines;
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the level of the Partnership’s processing and treating operations;
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the fees the Partnership charges and the margins it realizes for its services;
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the price of natural gas;
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the relationship between natural gas and NGL prices; and
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its level of operating costs.
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:
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the level of capital expenditures the Partnership makes;
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the cost of acquisitions, if any;
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its debt service requirements;
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fluctuations in its working capital needs;
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restrictions on distributions contained in its bank credit facility;
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its ability to make working capital borrowings under its bank credit facility to pay distributions;
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prevailing economic conditions; and
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the amount of cash reserves established by the general partner for the proper conduct of its business.
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:
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persons who are officers or directors of the company or who, on October 1, 2003, were, and at the time of presentation are, stockholders of the company (or to persons who are affiliates or associates of such officers, directors or stockholders), if the company is prohibited from participating in such opportunities by the omnibus agreement; or
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two affiliated stockholders with a substantial interest in our company, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P., or any other investment fund sponsored or managed by Yorktown Partners LLC, including any fund still to be formed, or to any of our directors who is an affiliate or designate of these entities.
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.
Substantially all of our partnership interests in the Partnership are subordinated to the common units.
We own 10,000,000 units representing limited partner interests in the Partnership, of which 7,001,000 are subordinated units and 2,999,000 are common units. During the subordination period, the subordinated units will not receive any distributions in a quarter until the Partnership has paid the minimum quarterly distribution of $0.25 per unit, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, on all of the outstanding common units. Distributions on the subordinated units are therefore more uncertain than distribution on the common units. Furthermore, no distributions may be made on the incentive distribution rights until the minimum quarterly distribution has been paid on all outstanding units. Therefore, distributions with respect to the incentive distribution rights are even more uncertain than distributions on the subordinated units. Neither the subordinated units nor the incentive distribution rights are entitled to any arrearages from prior quarters.
Generally, the subordination period ends, and the subordinated units convert to common units, only after December 31, 2007 and only upon the satisfaction of certain financial tests.
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:
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the allocation of shared overhead expenses to the Partnership and us;
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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and the Partnership, on the other hand, including obligations under the omnibus agreement;
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the determination of the amount of cash to be distributed to the Partnership’s partners and the amount of cash to be reserved for the future conduct of the Partnership’s business;
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the determination whether to make borrowings under the capital facility to pay distributions to partners; and
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any decision we make in the future to engage in activities in competition with the Partnership as permitted under our omnibus agreement with the Partnership.
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 by the Partnership typically increase its debt and subject it to other substantial risks, which could adversely affect its 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:
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the inability to integrate the operations of acquired businesses or assets;
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the diversion of management’s attention from other business concerns;
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the loss of customers or key employees from the acquired businesses;
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a significant increase in the Partnership’s indebtedness; and
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potential environmental or regulatory liabilities and title problems.
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 the Partnership’s 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 the Partnership’s opportunities for future acquisitions and could adversely affect its growth plans.
The Partnership is vulnerable to operational, regulatory and other risks associated with South Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes, because a significant portion of its assets are located in South Louisiana.
The Partnership’s 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:
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adverse weather conditions, including hurricanes and tropical storms;
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delays or decreases in production, the availability of equipment, facilities or services; and
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changes in the regulatory environment.
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 the Partnership’s 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 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 a 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 the Partnership’s 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 it to natural gas and NGL commodity price risks; and (3) part of its fees from its 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 its gross margins related to such purchases are based on a percentage of the index price. For the years ended December 31, 2004 and 2005, the Partnership purchased approximately 9% and 7.5%, 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 Partnership’s Gregory system and its Plaquemine plant and Gibson plant volumes, the Partnership purchases natural gas, processes natural gas and extracts NGLs, and then sells the processed natural gas and NGLs. A portion of the Partnership’s 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, the Partnership 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 it measures in Btus, from the gas stream in the form of the liquids or consumes it as fuel during processing, the Partnership reduces the Btu content of the natural gas. Accordingly, the Partnership’s 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 we expect this volatility to continue. For example, in 2004, the NYMEX settlement price for natural gas for the prompt month contract ranged from a high of $7.98 per MMBtu to a low of $5.08 per MMBtu. In 2005, the same index ranged from $13.91 per MMBtu to $6.12 per MMBtu. A composite of the OPIS Mt. Belvieu monthly average liquids price based upon the Partnership’s average liquids composition in 2004 ranged from a high of approximately $0.98 per gallon to a low of
approximately $0.66 per gallon. In 2005, the same composite ranged from approximately $1.17 per gallon to approximately $0.80 per gallon.
The Partnership may not be successful in balancing its 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 less than contracted volumes. Any of these actions could cause the Partnership’s purchases and sales not to be balanced. If the Partnership’s purchases and sales are not balanced, the Partnership will face increased exposure to commodity price risks and could have increased volatility on its 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 impact of weather on the demand for oil and natural gas;
•
the level of domestic oil and natural gas production;
•
the level of domestic industrial and manufacturing activity;
•
the availability of imported oil and natural gas;
•
actions taken by foreign oil and gas producing nations;
•
the availability of local, intrastate and interstate transportation systems;
•
the availability and marketing of competitive fuels;
•
the impact of energy conservation efforts; and
•
the extent of governmental regulation and taxation.
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.
Competition is intense in many of the Partnership’s markets. The principal areas of competition include obtaining gas supplies and the marketing and transportation of natural gas and NGLs. The Partnership’s competitors include major integrated oil companies, interstate and intrastate pipelines and natural gas gatherers and processors. Some of the Partnership’s competitors offer more services or have greater financial resources and access to larger natural gas supplies than it does.
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, its 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 its 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, the Partnership 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 the Partnership’s ability to connect new wells to its gathering facilities include its 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 the Partnership’s principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on its 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 its gathering systems and treating plants, is dedicated to certain natural gas reserves and wells for which the production will naturally decline over time. Accordingly, the Partnership’s 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 its existing assets or by constructing or acquiring new assets that have access to additional natural gas reserves, its 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 its business is through the construction of additions to its 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 its 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 Partnership’s 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.
The Partnership is in the process of completing a 143-mile pipeline and associated gathering lines from an area near Fort Worth, Texas into new markets accessed by the NGPL pipeline system. Drilling success in the Barnet Shale formation in the area has expanded productions beyond the capacity of the existing pipeline infrastructure to efficiently access markets. Capital cost to construct the pipeline and associated facilities are estimated to be approximately $115 million.
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 and Blue Water gas processing plants, 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 these plants, which are 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 its ability to enter such markets may be limited.
As the Partnership expands its operations into new geographic areas, the Partnership 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 its results of operations could be adversely affected.
The Partnership is exposed to the credit risk of its 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 are 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 the Partnership’s customers could adversely affect its results of operations.
The Partnership may not be able to retain existing customers or acquire new customers, which would reduce its revenues and limit its future profitability.
The renewal or replacement of existing contracts with the Partnership’s 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, 2005, approximately 74% 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 its 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 key customer could adversely affect 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, CELP 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:
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damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction and farm equipment;
•
leaks of natural gas, NGLs and other hydrocarbons; and
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fires and explosions.
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. The Partnership is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. The Partnership’s business interruption insurance covers only its Gregory processing plant. If a significant accident or event occurs that is not fully insured, it could adversely affect the Partnership’s 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 believes to be acceptable pricing levels. A lower level of economic activity could also result in a decline in energy consumption, which could adversely affect the Partnership’s revenues or restrict its future growth.
Federal, state or local regulatory measures could adversely affect the Partnership’s business.
While the Federal Energy Regulatory Commission, or FERC, generally does not regulate any of the Partnership’s operations, directly or indirectly, FERC influences certain aspects of the Partnership’s business and the market for its products. As a raw natural gas gatherer, the Partnership generally is exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects the Partnership’s business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Some of the Partnership’s intrastate natural gas transmission pipelines are subject to regulation as a common carrier and as a gas utility by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates the Partnership charges for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, the Partnership’s business may be adversely affected.
Other state and local regulations also affect the Partnership’s business. The Partnership 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 the Partnership 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 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, or DOT, 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 $0.3 million for the year ended December 31, 2005 and $1.9 million in 2004 and the Partnership expects the costs for compliance with TRRC and DOT regulations to be $2.4 million in the aggregate during 2006 and 2007. If the Partnership’s pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then it may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.
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 its 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, the Partnership’s 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 Partnership’s use of derivative financial instruments has in the past and could in the future result in financial losses or reduce its 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 the Partnership’s 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 its gathering, transmission, treating, processing and producer services businesses would materially impact its financial condition.
The Partnership relies exclusively on the revenues generated from its gathering, transmission, treating, processing and producer services businesses, and as a result its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to the Partnership’s lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if it maintained more diverse assets.
The Partnership’s success depends on key members of its 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 has entered 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.
Item 1B.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 2.
Item 2.
Properties
A description of the Partnership’s properties is contained in “Item 1. Business.”
Title to Properties
Substantially all of the Partnership’s pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. CELP has obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which the Partnership’s pipeline was built was purchased in fee. The Partnership’s processing plants are located on land that it leases or owns in fee. Their treating facilities are generally located on sites provided by producers or other parties.
We believe that CELP 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 assets or from the Partnership’s interest in these assets or should materially interfere with their use in the operation of the business.
Item 3.
Item 3.
Legal Proceedings
Our operations and those of CELP are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we or the Partnership may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. These include litigation on disputes related to contracts, property rights, use or damage and personal injury. We do not believe that any pending or threatened claim or dispute is material to our financial results or our operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, this insurance may not be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
No matters were submitted to security holders during the fourth quarter of the year ended December 31, 2005.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the NASDAQ National Market under the symbol “XTXI”. Our common stock began trading on January 12, 2004. Before that date, there was no public market for shares of our common stock. On February 22, 2006, the market price for our common stock was $80.22 per share and there were approximately 7,400 record holders and beneficial owners (held in street name) of the shares of our common stock.
The following table shows the high and low closing sales prices per share, as reported by the NASDAQ National 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:
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federal income taxes, which we are required to pay because we are taxed as a corporation;
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the expenses of being a public company;
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other general and administrative expenses;
•
capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s 2.0% general partner interest; and
•
reserves our board of directors believes prudent to maintain.
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.
Item 6.
Item 6.
Selected Financial Data
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 Corpus Christi system, the Gregory gathering system and the Gregory processing plant beginning in May 2001, the Vanderbilt system beginning in December 2002, the Mississippi pipeline system and the Seminole processing plant beginning in June 2003, and the LIG assets beginning in April 2004, the Graco assets beginning in January 2005, the Cardinal assets beginning in May 2005, and the El Paso south Louisiana processing assets beginning in November 1, 2005.
The table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
(1)
We recognized gains of $65.1 million in 2005, $18.4 million in 2003 and $11.8 million in 2002 as a result of the Partnership issuing additional units at prices per unit greater than our equivalent carrying value.
(2)
Per share amounts have been adjusted for the two-for-one stock split made in conjunction with our initial public offering in January 2004.
(3)
Gross margin is defined as revenue, including treating fee revenues, less related cost of purchased gas.
(4)
Processed volumes include a daily average for the south Louisiana processing plants for November 2005 and December 2005, the two-month period these assets were operated by the Partnership.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in this report.
Overview
Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage through its subsidiaries in the gathering, transmission, treating, processing and marketing of natural gas and NGLs. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of
partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 2,999,000 common units and 7,001,000 subordinated units, representing approximately 38% of the limited partner interests in Crosstex Energy, L.P. and (ii) 100% ownership interest in Crosstex Energy GP, L.P., the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.
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 $0.51 per unit for the quarter ended December 31, 2005. As a result, our distributions from the Partnership pursuant to our ownership of our 10,000,000 common and subordinated units have increased from $2.5 million for the quarter ended March 31, 2003 to $5.1 million for the quarter ended December 31, 2005; our distributions pursuant to our 2% general partner interest have increased from $74,000 to approximately $4.3 million; and our distributions pursuant to our incentive distribution rights have increased from nothing to $4.0 million. As a result, we have increased our dividend from $0.30 per share for the quarter ended March 31, 2004 (the first dividend payout after our initial public offering) to $0.56 per share for the quarter ended December 31, 2005.
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 along the Texas Gulf Coast and in Mississippi and Louisiana. 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, 2005, 76% of our gross margin was generated in the Midstream division, with the balance in the Treating division. CELP focuses on gross margin to manage its business because its business is generally to purchase and resell gas for a margin, or to gather, process, transport, market or treat gas or NGLs for a fee. CELP buys and sells most of its gas at a fixed relationship to the relevant index price so margins are not significantly affected by changes in gas prices. As explained under “Commodity Price Risk” below, it enters into financial instruments to reduce volatility in gross margin due to price fluctuations.
Since the formation of the Partnership’s predecessor, it has grown significantly as a result of construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2000 through December 31, 2005, the Partnership has invested over $973 million to develop or acquire new assets. The purchased assets were acquired from numerous sellers at different periods and were accounted for under the purchase method of accounting. Accordingly, the results of operations for such acquisitions are included in our
financial statements only from the applicable date of the acquisition. As a consequence, the historical results of operations for the periods presented may not be comparable.
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 natural gas liquids 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 and from natural gas liquids at a non-operated processing plant. CELP generates revenues from five primary sources:
•
purchasing and reselling or transporting natural gas on the pipeline systems it owns;
•
processing natural gas at its processing plants and fractionating and marketing the recovered natural gas liquids;
•
treating natural gas at its treating plants;
•
recovering carbon dioxide and natural gas liquids at a non-operated processing plant; and
•
providing off-system marketing services for producers.
The bulk of the Partnership’s operating profits are derived from the margins it realizes for purchasing and reselling natural gas through its pipeline systems. Generally, the Partnership buys gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. The Partnership then transports and resells the gas. The resale price is 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:
•
a volumetric fee based on the amount of gas treated, which accounted for approximately 51% and 53% of the operating income in the Treating division for the years ended December 31, 2005 and 2004, respectively;
•
a fixed fee for operating the plant for a certain period, which accounted for approximately 38% and 43% of the operating income in the Treating division for the years ended December 31, 2005 and 2004, respectively; or
•
a fee arrangement in which the producer operates the plant, which accounted for approximately 11% and 4% of the operating income in the Treating division for the years ended December 31, 2005 and 2004, respectively.
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore, do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.
We modified certain terms of certain outstanding options on our common stock in the first quarter of 2003 which allowed the option holders to elect to be paid in cash for the modified options based on the fair value of the options. These modifications resulted in variable award accounting for the modified options until the option holders elected to cash out the options or the election to cash out the options lapsed. We were responsible for paying the intrinsic value of the options for the holders who elected to cash out their options. December 31, 2003 was the last valuation date that a holder of modified options could elect the cash-out alternative. Accordingly, effective
January 1, 2004, we ceased applying variable accounting for the remaining modified options. We recognized total compensation expense of approximately $5.0 million related to these modified options in 2003.
The Partnership has grown significantly through asset purchases in recent years, which creates many of the major differences when comparing operating results from one period to another. The most significant asset purchases since January 1, 2003, are the acquisitions of the DEFS assets, the LIG assets, and the El Paso processing and liquids business in south Louisiana. It also acquired treating operations totaling $16.0 million in 2005.
On November 1, 2005 CELP acquired El Paso Corporation’s processing and liquids business in South Louisiana for $481.0 million. The assets acquired include 2.3 Bcf/d of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines. The primary facilities and other assets acquired consist of: (1) the Eunice processing plant and fractionation facility; (2) the Pelican processing plant; (3) the Sabine Pass processing plant; (4) a 23.85% interest in the Blue Water gas processing plant; (5) the Riverside fractionator and loading facility; (6) the Cajun Sibon pipeline and (7) the Napoleonville natural gas liquid storage facility.
On January 2, 2005 the Partnership acquired all of the assets of Graco Operations for $9.26 million. Graco’s assets consisted of 26 treating plants and associated inventory. On May 1, 2005 it acquired all of the assets of Cardinal Gas Services for $6.7 million. Cardinal’s assets consisted of nine gas treating plants, 19 operating wellhead gas processing plants for dewpoint suppression, and equipment inventory.
In April 2004 the Partnership acquired LIG Pipeline Company and its subsidiaries (collectively, “LIG”) from a subsidiary of American Electric Power (“AEP”) for $73.7 million in cash. The principal assets acquired consist of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to the south and southeast Louisiana and five processing plants, including three idle plants that straddle the pipeline in three locations and have a total processing capacity of 663,000 MMBtu/d. The system has a throughput capacity of 900,000 MMBtu/d and average throughput at the time of our acquisition was approximately 560,000 MMBtu/d. Customers include power plants, municipal gas systems, and industrial markets located principally in the industrial corridor between New Orleans and Baton Rouge. The LIG system is connected to several interconnected pipelines and the Jefferson Island Storage facility providing access to additional system supply. It subsequently sold one of the idle plants with a capacity of 225,000 MMBtu/d in September 2005 and realized a gain on sale of $8.0 million.
The Partnership acquired the Duke Energy Field Services assets, or DEFS assets, in June 2003 for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. The acquisition provided CELP with a new core area for growth in south central Mississippi, expanded its presence in West Texas and enabled it to enter the business of carbon dioxide separation.
Other Assets. We own two inactive gas plants and a receivable associated with the Enron Corp. bankruptcy 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 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.
We currently have a net operating loss carryforward of $33.6 million as of December 31, 2005 for federal income taxes and state loss carryforwards of $7.3 million. We estimate that our net operating loss carryforwards will
be utilized to offset federal taxable income in 2006 and 2007. In years after 2007, however, we do not expect to have this net operating loss carryforward to offset our income. As a result, 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 stock holders 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. However, we do not expect such a change in ownership to limit our utilization of carryforwards prior to their 20-year expiration 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 we buy and sell, margins are not affected by such changes because the gas is bought and sold at a fixed relationship to the relevant index. Therefore, while changes in the price of gas can have very large impacts on revenues and cost of revenues, 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 producer services business for the year ended December 31, 2005.
(1)
Gas sold is less than gas purchased due to production of natural gas liquids on certain assets included in the south Texas system.
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 $1.6 million on an annual basis (before consideration of hedge positions). As of December 31, 2005, it has hedged approximately 78% of its exposure to such fluctuations in natural gas prices for 2006. CELP expects to continue to hedge its exposure to gas prices when market opportunities appear attractive.
CELP processes approximately 59% of its volume 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 41% of volume as fixed fee per unit processed. Under percent of proceeds contracts, it is exposed to changes in the prices of natural gas liquids. For the years 2006 and 2007, it has purchased puts or entered into forward sales covering all of its anticipated minimum share of natural gas liquids production.
The Partnership expects to continue to hedge its exposure to gas production which it purchases at a percentage of index when market opportunities appear attractive.
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, 2005, the Partnership purchased a small amount (approximately 5.5%) 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 94.5% 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 plant also receives 50% of the NGLs produced by the plant. Therefore, the Partnership has commodity price exposure due to variances in the prices of NGLs. During 2005, its share of NGLs totaled 5.9 million gallons at an average price of $0.91 per gallon. The Partnership executed forward sales on approximately 80% of its anticipated 2006 share of NGLs.
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, 2005 Compared to Year Ended December 31, 2004
Gross Margin. Midstream gross margin was $122.1 million for the year ended December 31, 2005 compared to $86.8 million for the year ended December 31, 2004 an increase of $35.2 million, or 41%. This increase was primarily due to acquisitions, volatile prices in the last half of the year and operational improvements on existing systems.
The acquisition of El Paso Corporation’s natural gas processing and liquids business in south Louisiana contributed $14.1 million of gross margin in the fourth quarter of 2005. The acquisition of the LIG assets on April 1, 2004 contributed $6.3 million to midstream gross margin in 2005 in our first full year of ownership. In addition, the acquisition of all outside interests in Crosstex Pipeline Partners, Ltd. as of December 31, 2004 accounted for a gross margin increase of $1.7 million. Relatively high and volatile natural gas prices during the quarters created favorable margin opportunities on several systems, offset by the negative impact on processing margins of high gas prices, as certain gas was no longer economical to process. The impact of these high and volatile gas prices on midstream operations was a gross margin increase of $5.4 million. During the fourth quarter, declines in gas prices created an imbalance gain of $4.5 million and made processing more profitable. Operational improvements and volume increases contributed margin growth of $5.1 million on the Vanderbilt, Arkoma, and Denton County systems. In addition, the Gregory Gathering system had a margin increase of $1.7 million primarily due to two measurement disputes which were settled during the year.
Treating gross margin was $38.9 million for the year ended December 31, 2005 compared to $25.5 million in the same period in 2004, an increase of $13.4 million, or 53%. The increase in treating plants in service from 74 plants at December 31, 2004 to 112 plants at December 31, 2005 contributed approximately $7.1 million in gross margin. Existing plant assets contributed $5.0 million in gross margin growth due primarily to plant expansion projects and increased volumes. The acquisition and installation of dew point control plants in 2005 contributed an additional $0.6 million to gross margin.
Profit on Energy Trading Activities. The profit on energy trading activities was $1.6 million for the year ended December 31, 2005 compared to $2.2 million for the year ended December 31, 2004. The decrease in profit on energy trading activities is primarily due to a volume decrease associated with contracts not renewed in 2005. This is an activity the Partnership is de-emphasizing.
Operating Expenses. Operating expenses were $56.8 million for the year ended December 31, 2005 compared to $38.4 million for the year ended December 31, 2004, an increase of $18.4 million, or 48%. An increase of $5.3 million was associated with the acquisition of the El Paso assets. Increases of $4.6 million were associated with the acquisition of the LIG assets as they were owned for the entire year instead of nine months in 2004. Midstream operating expenses also increased by $2.6 million due to small acquisitions and expansions of systems and the addition of compressors or other rental services. The growth in treating plants in service due to acquisition of the Graco assets and the Cardinal assets as well as internal growth increased operating expenses by $5.2 million. Operations expense includes stock-based compensation expense of $0.4 million and $0.2 million in 2005 and 2004, respectively.
General and Administrative Expenses. General and administrative expenses were $34.1 million for the year ended December 31, 2005, compared to $22.0 million for the year ended December 31, 2004, an increase of $12.1 million, or 55%. A significant contributor was additional staffing-related costs, an incremental $6.0 million over 2004. The staff additions required to manage and optimize our acquisitions account for the majority of the change, although a number of leadership and strategic positions were added that will allow us to absorb future growth more efficiently. Other expenses related to growth, including office rent, utilities, and travel expenses, account for $2.6 million of the increase. General and administrative expense includes stock-based compensation expense of $3.7 million in 2005 and $0.8 million in 2004. The increase in stock-based compensation primarily relates to restricted stock and unit grants and $0.4 million in accelerated options.
(Gain) Loss on Derivatives. We had a loss on derivatives of $10.0 million for the year ended December 31, 2005 compared to a gain on derivatives of $0.3 million for the year ended December 31, 2004. The loss in 2005 includes a $9.2 million loss on put options acquired in the third quarter of 2005 related to the acquisition of the El Paso assets and a loss of $0.8 million associated with derivatives for the third-party on-system financial transactions and storage financial transactions primarily due to higher commodity prices at year end. We acquired put options, or rights to sell a portion of the liquids from the plants at a fixed price over a two-year period beginning January 1, 2006 for a premium of $18.7 million as part of the overall risk management plan related to the acquisition of the El Paso assets which closed on November 1, 2005. In December 2005 we sold a portion of these put options for $4.3 million. These put options did not qualify as hedges as of December 31, 2005 and were marked to market through our consolidated statement of operations. The puts represent options, but not the obligation, to sell the
related underlying liquids volumes at a fixed price. As the price of the underlying liquids increased significantly in the period, the value of the put options declined, which is reflected in gain/loss on derivatives.
Gain on Sale of Property. During 2005, the Partnership sold an inactive gas processing facility acquired as part of the LIG acquisition, which accounted for a substantial part of the $8.1 million gain on sale of property.
Depreciation and Amortization. Depreciation and amortization expenses were $36.1 million for the year ended December 31, 2005 compared to $23.0 million for the year ended December 31, 2004, an increase of $13.1 million, or 57%. Of the increase, the acquisition of the El Paso assets contributed $5.5 million and the LIG assets contributed $1.3 million. New treating plants placed in service resulted in an increase of $2.3 million. The remaining $3.9 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Dallas office, computer software and equipment, and expansions on midstream assets.
Interest Expense. Interest expense was $15.3 million for the year ended December 31, 2005 compared to $9.1 million for the year ended December 31, 2004, an increase of $6.2 million, or 68%. The increase relates primarily to an increase in average debt outstanding. Average higher interest rates also increased from 2004 to 2005 (weighted average rate of 6.1% in 2004 compared to 6.3% in 2005).
Other Income. Other income was $0.4 million for the year ended December 31, 2005 compared to $0.8 million for the year ended December 31, 2004. Other income in 2004 includes $0.3 related to a reimbursement for a construction project in excess of our costs for such project.
Gain on Issuance of Units of the Partnership. As a result of the Partnership issuing additional units in November 2005 at a price per unit greater than our equivalent carrying value, our share of the net assets in the Partnership increased by $65.1 million. Accordingly, we recognized a $65.1 million gain in 2005.
Income Tax Expense. We provide for income taxes using the asset and 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. Our income tax provision was $30.0 million in 2005 compared to $5.1 million in 2004, an increase of $25.0 million. The increase in the tax provision was primarily due to the taxes provided on the $65.1 million gain on issuance of units of the Partnership during 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 $3.6 million to $4.7 million for the year ended December 31, 2005 compared to $8.2 million for the year ended December 31, 2004. The Partnership’s net income decreased from $23.7 million in 2004 to $19.2 million in 2005 contributing to the decrease in the interest of non-controlling partners. The non-controlling partners share of the Partnership net income was further reduced by the increase in net income allocated to us for our incentive distributions which increased from $5.6 million in the year ended December 31, 2004 to $10.7 million in the year ended December 31, 2005. Income from the Partnership is allocated to us for our incentive distributions less stock-based compensation attributable to our options and restricted units with the remaining income being allocated pro rata to the 2% general partner interest and the common units and subordinated units (excluding senior subordinated units). Distributions from the Partnership will generally be made 98% to the common and subordinated unitholders (other than the senior subordinated unitholders) and 2% to the Company as the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally the Company is entitled to 13% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48% of amounts the Partnership distributes in excess of $0.375 per unit.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Gross Margin. Midstream gross margin was $86.8 million for the year ended December 31, 2004 compared to $43.3 million for the year ended December 31, 2003, an increase of $43.5 million, or 101%. This increase was primarily due to the acquisitions of the LIG assets on April 1, 2004 and DEFS assets on June 30, 2003, which added an incremental $27.7 million and $7.9 million, respectively, to midstream gross margin. The volume growth of 956,000 MMBtu/d, or 97%, in gathering, transportation, and processing was primarily due to the acquired LIG and
DEFS assets. Also contributing to improved margins were higher processing margins and volumes from existing gas processing operations, which increased margins by $3.4 million from 2004 to 2003.
Treating gross margin was $25.5 million for the year ended December 31, 2004 compared to $16.4 million in the year ended December 31, 2003, an increase of $9.1 million, or 55%. Of this increase, $4.5 million was due to the Seminole Plant, one of the assets acquired from DEFS, being owned for a full year. The Seminole Plant has increased from 20% of operating income in 2003 to 34% of operating income during 2004, as the Seminole Plant was only owned for the last six months of 2003. Also contributing to the significant growth was the placement of an additional 37 plants in service since December 31, 2003, which was offset in part by 15 plant retirements. The net plant additions of 22 generated $4.1 million in additional gross margin.
Operating Expenses. Operating expenses were $38.4 million for the year ended December 31, 2004 compared to $19.9 million for the year ended December 31, 2003, an increase of $18.5 million, or 93%. Increases of $3.5 million and $9.5 million were associated with the acquisition of the DEFS and LIG assets, respectively. General operations expense (expenses not directly related to specific assets) was $6.0 million for 2004 compared to $1.7 million for 2003. The majority of the $4.3 million increase was related to higher technical services support required by the newly-acquired assets and additional expenditures related to our pipeline integrity program. The growth in treating plants in service increased operating expenses by $1.2 million. Stock-based compensation expense included in operating expenses included $0.2 million and $2.1 million in 2004 and 2003, respectively. During 2003, certain outstanding options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004 the remaining options are accounted for as fixed options. Stock-based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.
General and Administrative Expenses. General and administrative expenses were $22.0 million for the year ended December 31, 2004 compared to $14.8 million for the year ended December 31, 2003, an increase of $7.2 million, or 49%. A significant part of the increased expenses was $5.0 million of additional staffing related costs. The staff additions required to manage and optimize our LIG and DEFS acquisitions account for the majority of the change, although a number of leadership and strategic positions were added that will allow us to absorb future growth more efficiently. Consistent with staffing for future growth, an additional $1.0 million in consulting costs were made to upgrade our systems, providing a more scalable infrastructure. Sarbanes Oxley compliance costs were an additional $1.1 million for 2004 compared to zero in 2003. Other expenses, including audit and tax fees, office rent, K-1 preparation fees and travel expenses, account for $1.7 million of the increase. Stock-based compensation included in general and administrative expenses was $0.8 million and $3.2 million in 2004 and 2003, respectively. During 2003, certain outstanding options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, the remaining options are accounted for as fixed options. Stock-based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.
Impairment. An impairment of $1.0 million was recognized during 2004 related to a processing plant that is owned directly by us. This plant has been inactive since late 2002 when the operator of the wells behind the plant cancelled its drilling plans for the area. An impairment of the contracts associated with the plant was recorded in 2002 but the value of the plant was not impaired because we intended to restart or relocate the plant. Drilling activity has increased in the area near the plant and processing margins have improved during 2004 so management decided to more fully evaluate the cost of restarting this idle plant. Management determined that it would be more commercially feasible to put a new plant at the plant site than to invest the capital necessary to restart the plant. If we do not restart the plant, our engineers estimate that the plant would receive very little, if any, value upon the sale of the plant. Therefore, we have impaired the full value of the plant during 2004.
Depreciation and Amortization. Depreciation and amortization expenses were $23.0 million for the year ended December 31, 2004 compared to $13.5 million for the year ended December 31, 2003, an increase of $9.5 million, or 70%. The increase related to the DEFS assets was $2.6 million and the increase related to the LIG assets was $3.3 million. New treating plants placed in service resulted in an increase of $2.2 million. The remaining $1.4 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant and the consolidation of Denton County assets.
Interest Expense. Interest expense was $9.1 million for the year ended December 31, 2004 compared to $3.1 million for the year ended December 31, 2003, an increase of $6.0 million, or 194%. The increase relates primarily to an increase in average debt outstanding. Average interest rates also increased from 2003 to 2004 (weighted average rate of 6.1% in 2004 compared to 5.4% in 2003).
Other Income. Other income was $0.8 million for the year ended December 31, 2004 compared to $0.2 million for the year ended December 31, 2003. Other income in 2004 includes $0.3 million related to a reimbursement for a construction project in excess of our costs for such projects.
Interest of Non-controlling Partners in the Partnership’s Net Income. We recorded an expense of $8.2 million in 2004 and $5.2 million in 2003 associated with the interests of non-controlling partners in the Partnership. This expense increased between periods because the Partnership’s net income increased by $8.5 million from 2003 to 2004 and the non-controlling partners’ ownership in the Partnership increased from 31.5% to 43.8% in September 2003 as a result of the issuance of additional common units to the public shareholders. The increases related to Partnership net income and non-controlling partner ownership were partially offset by the impact of incentive distributions increased from $1 million for the year ended December 31, 2003 to $5.6 million for the year ended December 31, 2004. Income from the Partnership is allocated to us for its incentive distributions with the remaining income being allocated pro rata to the 2% general partner interest and the common unit and subordinated units.
Income Tax Expense. Income tax expense was $5.1 million for the year ended December 31, 2004 compared to $10.1 million for the year ended December 31, 2003, a decrease of $5.0 million. The decrease in the tax provision was primarily due to the taxes provided on the $18.4 million gain on issuance of units of the Partnership during 2003 partially offset by taxes provided on higher operating income in 2004.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Note 2 of the Notes to Consolidated Financial Statements.
Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services at the time the natural gas or natural gas liquids are delivered or at the time the service is performed.
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.
In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities 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 Commercial Services. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer’s natural gas. In other cases, the Partnership purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas.
The Partnership manages its price risk related to future physical purchase or sale commitments for its Commercial Services activities 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. However, the Partnership is subject to counterparty risk for both the physical and financial contracts. The Partnership’s energy trading contracts qualify as derivatives under SFAS No. 133, and accordingly, the Partnership continues to use mark-to-market accounting for both physical and financial contracts of its Commercial Services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to the Partnership’s Commercial Services natural gas marketing activities are recognized in earnings as profit or loss on energy trading immediately.
For each reporting period, the Partnership records the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period in addition to the realized gains or losses on settled activities are reported as profit or loss on energy trading activities in the statements of operations.
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:
•
changes in general economic conditions in regions in which our markets are located;
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the availability and prices of natural gas supply;
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the Partnership’s ability to negotiate favorable sales agreements;
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the risks that natural gas exploration and production activities will not occur or be successful;
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the Partnership’s dependence on certain significant customers, producers, and transporters of natural gas; and
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competition from other midstream companies, including major energy producers.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Liquidity and Capital Resources
Cash Flows. Net cash provided by operating activities was $12.8 million for the year ended December 31, 2005 compared to cash provided by operations of $46.3 million for the year ended December 31, 2004. Income before non-cash income and expenses was $61.7 million in 2005 and $47.2 million in 2004. Changes in working capital used $48.9 million in cash flows from operating activities in 2005 and provided $.8 million in cash flows from operating activities in 2004. Income before non-cash income and expenses increased between years primarily due to asset acquisitions as discussed in “Results of Operations - Year Ended December 31, 2005 Compared to Year Ended December 31, 2004.” Changes in working capital are primarily due to the timing of collections at the end of the quarterly periods. The Partnership collects and pays large receivables and payables at the end of each calendar month and the timing of these payments and receipts may vary by a day or two between month-end periods, causing these fluctuations. Increased natural gas and natural gas liquids prices together with the acquisition of the El Paso assets contributed to increases in accounts receivable, accrued gas sales, accounts payable, accrued gas purchases, imbalance receivables and payables and inventory costs during 2005.
Net cash used in investing activities was $614.8 million and $124.4 million for the year ended December 31, 2005 and 2004, respectively. Net cash used in investing activities during 2005 related to the El Paso assets ($489.4 million), the Graco assets ($9.3 million), and the Cardinal assets ($6.7 million). The remaining cash used in investing activities for 2005 relates to internal growth projects including expenditures of the North Texas Pipeline (“NTPL”) project of approximately $80.0 million, $22.9 million for buying, refurbishing and installing treating plants and $18.3 million for expansions, well connections and other capital projects on the pipeline, gathering and processing assets. Net cash used in investing activities during 2004 related to the LIG acquisition ($73.7 million) and the purchase of the outside partner interests in Crosstex Pipeline Partners ($5.1 million) as well as internal growth projects. The primary internal growth projects during 2004 were buying, refurbishing and installing treating plants ($24.5 million).
Net cash provided by financing activities was $592.4 million and $99.1 million for the years ended December 31, 2005 and 2004, respectively. Financing activities in 2005 relate to proceeds from the sale of common units and subordinated units discussed below and increased borrowings under the Partnership’s credit facility. Financing activities for 2005 relate primarily to funding the acquisitions of the El Paso assets, Graco assets, Cardinal assets and to funding the NTPL project. Financing activities for 2004 relate primarily to funding the LIG acquisition. Distributions to partners of CELP totaled $43.3 million in 2005 compared to distributions of $34.3 million in 2004 due to increases in the distribution levels between years, including incentive distributions. Drafts payable decreased by $8.8 million requiring the use of cash in 2005 compared to an increase in drafts payable of $28.2 million providing cash from financing activities in 2004. In order to reduce our interest costs, we borrow money to fund outstanding checks as they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility.
Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of December 31, 2005 and 2004.
June 2005 Sale of Senior Subordinated Units. In June 2005, CELP issued 1,495,410 senior subordinated units in a private offering for net proceeds of $50.0 million, excluding our $1.1 million general partner contribution and after expenses associated with the sale. The senior subordinated units were issued at $33.44 per unit, which represents a discount of 13.7% to the market value of common units on such date, and automatically converted to common units on a one-for-one basis on February 24, 2006. The senior subordinated units were not entitled to distributions of available cash until they converted to common units.
November 2005 Sale of Senior Subordinated B Units. On November 1, 2005, CELP issued 2,850,165 Senior Subordinated Series B Units in a private placement for a purchase price of $36.84 per unit. CELP received net proceeds of approximately $105.0 million, excluding our $2.1 million general partner contribution and after 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 Units and were not entitled to distributions paid on November 14, 2005.
November 2005 Public Offering. In November and December 2005, CELP 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 $118.4 million, excluding our $2.5 million general partner contribution and after expenses associated with the offering.
Senior Secured Notes. In November 2005, CELP completed a private placement of $85.0 million of senior secured notes pursuant to the master shelf agreement with an institutional lender with an interest rate of 6.23% and a maturity of ten years.
Crosstex Energy, Inc. Initial Public Offering. In January 2004, we completed an initial public offering of our common stock whereby our existing shareholders sold 2,306,000 shares of common stock and we issued 345,900 shares of common stock at a public offering price of $19.50 per share. We received net proceeds of approximately $5.2 million from the common stock issuance. Additionally, and in conjunction with the public offering, our existing shareholders also repaid approximately $4.9 million in shareholder notes receivable. We had $12.9 million cash on hand at December 31, 2005, and we have no annual capital expenditure requirements. As a result, we believe we have adequate cash on hand for our operating requirements for the foreseeable future.
Capital Requirements of the Partnership. 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:
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maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain existing operating capacity of the Partnership’s assets and to extend their useful lives, or other capital expenditures which do not increase the Partnership’s cash flows; and
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growth capital expenditures such as those to acquire additional assets to grow the Partnership’s business, to expand and upgrade gathering systems, transmission capacity, processing plants or treating plants, and to construct or acquire new pipelines, processing plants or treating plants.
Given the Partnership’s objective of growth through acquisitions and large capital expansions, 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 believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.51 per quarter and to fund a portion of its anticipated capital expenditures through December 31, 2006. Total capital expenditures are budgeted to be approximately $120 million in 2006. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below and with future issuances of units. The Partnership’s ability to pay distributions to its unit holders and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond its control.
Total Contractual Cash Obligations. A summary of the Partnership’s total contractual cash obligations as of December 31, 2005, is as follows:
The above table does not include any physical or financial contract purchase commitments for natural gas.
The unconditional purchase obligations for 2005 primarily relate to the purchase of pipe for the construction of the North Texas Pipeline and for gas turbine gearbox and controls required for the south Louisiana assets.
Description of Indebtedness
As of December 31, 2005 and 2004, long-term debt consisted of the following (dollars in thousands):
On March 31, 2005, the Partnership amended its bank credit facility, increasing availability under the facility to $250 million, eliminating the distinction between an acquisition and working capital facility and extending the maturity date from June 2006 to March 2010. On November 1, 2005, CELP amended its bank credit facility to, among other things, provide for revolving credit borrowings up to a maximum principal amount of $750 million and the issuance of letters of credit in the aggregate face amount of up to $300 million, which letters of credit reduce the credit available for revolving credit borrowings. The bank credit agreement includes procedures for additional financial institutions selected by it to become lenders under the agreement, or for any existing lender to increase its commitment in an amount approved by the Partnership and the lender, subject to a maximum of $300 million for all such increases in commitments of new or existing lenders. The maturity date was also extended to November 2010.
The credit facility was used for the El Paso acquisition and will be used to finance the acquisition and development of gas gathering, treating, and processing facilities, as well as general partnership purposes. At December 31, 2005, $407.0 million was outstanding under the credit facility, including $85.0 million of letters of credit, leaving approximately $343.0 available for future borrowings. The credit facility will mature in November 2010, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the credit facility may be re-borrowed.
The obligations under the bank credit facility are secured by first priority liens on all of the Partnership’s material pipeline, gas gathering, treating, and processing assets, all material working capital assets and a pledge of all of its 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 bank credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.
Indebtedness under the credit facility bears interest at the Partnership’s option at the administrative agent’s reference rate plus 0.0% to 0.50% or LIBOR plus 1.00% to 2.00%. The applicable margin varies quarterly based on the Partnership’s leverage ratio. The fees charged for letters of credit range from 1.00% to 2.00% per annum, plus a fronting fee of 0.125% per annum. The Partnership incurs quarterly commitment fees based on the unused amount of the credit facilities.
The credit agreement prohibits the Partnership from declaring distributions to unitholders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. In addition, the bank credit facility contains various covenants that, among other restrictions, limits the Partnership’s ability and the ability of its subsidiaries to:
•
incur indebtedness;
•
grant or assume liens;
•
make certain investments;
•
sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
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make distributions;
•
change the nature of its business;
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enter into certain commodity contracts;
•
make certain amendments to its or the Operating Partnership’s partnership agreement; and
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engage in transactions with affiliates.
The credit facility also adjusted financial covenants requiring the Partnership to maintain:
•
a maximum ratio of total funded debt to consolidated earnings before interest, taxes, depreciation and amortization (each as defined in the credit agreement), measured quarterly on a rolling four-quarter basis of (i) 5.25 to 1.00 for any fiscal quarter ending during the period commencing on the effective date of the credit facility and ending March 31, 2006, (ii) 4.75 to 1.00 for any fiscal quarter ending during the period commencing on April 1, 2006, and (iii) 4.00 to 1.00 for any fiscal quarter ending thereafter, pro forma for any asset acquisitions (but during an acquisition adjustment period (as defined in the credit agreement), the maximum ratio is increased to 4.75 to 1); and
•
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:
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failure to pay any principal, interest, fees, expenses or other amounts when due;
•
failure to observe any agreement, obligation, or covenant in the credit agreement, subject to cure periods for certain failures;
•
certain judgments against the Partnership or any of its subsidiaries, in excess of certain allowances;
•
certain ERISA events involving the Partnership or its subsidiaries;
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cross defaults to certain material indebtedness;
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certain bankruptcy or insolvency events involving the Partnership or its subsidiaries;
•
a change in control (as defined in the credit agreement); and
•
the failure of any representation or warranty to be materially true and correct when made.
Senior Secured Notes. In June 2003, the Partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million aggregate principal amount of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, the Partnership issued $10.0 million aggregate principal amount of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years. In June 2004, the master shelf agreement was amended, increasing the amount issuable under the agreement from $50.0 million to $125.0 million. In June 2004, the Partnership issued $75.0 million aggregate principal amount of senior secured notes with an interest rate of 6.96% and a maturity of ten years. In June 2005, the master shelf agreement was amended, increasing the amount issuable under the agreement from $125.0 million to $200.0 million. In November 2005, the Partnership issued $85.0 million aggregate principal amount of senior secured notes with an interest rate of 6.23% and a maturity of ten years.
The notes represent the Partnership’s senior secured obligations and 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 the Partnership’s obligations 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 of its equity interests in certain of its subsidiaries. The senior secured notes are guaranteed by the Partnership’s significant subsidiaries.
The initial $40.0 million of senior secured notes 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 $75.0 million senior secured notes issued in June 2004 and the $85.0 million issued in November 2005 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.
The master shelf agreement relating to the notes contains substantially the same covenants and events of default as the bank credit facility.
If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of more than 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable.
The Partnership was in compliance with all debt covenants at December 31, 2005 and 2004 and expects to be in compliance for the next twelve months.
Intercreditor and Collateral Agency Agreement. In connection with the execution of the master shelf agreement in June 2003, the lenders under the bank credit facility and the initial purchasers of the senior secured notes entered into an Intercreditor and Collateral Agency Agreement, which was acknowledged and agreed to by our operating partnership and its subsidiaries. As amended in 2005, this agreement appoints Bank of America to act as collateral agent and authorized the bank to execute various security documents on behalf of the lenders under the bank credit facility and the initial purchases 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 Crosstex Energy Services, L.P.’s obligations under the bank credit facility and the master shelf agreement.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2003, 2004 or 2005. 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 the Partnership’s existing agreements, it has and will continue to pass along increased costs to our customers in the form of higher fees.
Environmental and Other Contingencies
The Partnership’s operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The Partnership believes it is 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 - Crosstex Energy, L.P. - Environmental Matters.”
Recent Accounting Pronouncements
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate
the fair value of an asset retirement obligation under FASB Statement No. 143. FIN 47 is effective at December 31, 2005. At December 31, 2005, the Partnership cannot estimate the timing and/or method of settlement for substantially all their assets where a legal obligation to perform an asset retirement activity exists and therefore adoption of FIN 47 had no impact on the Partnership’s financial position or results of operations.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, which requires compensation related to all stock-based awards, including stock options be recognized in the consolidated financial statements. The provisions of SFAS No. 123R are effective for the first annual reporting period that begins after June 15, 2005. The Company will adopt this standard on January 1, 2006 and will elect the modified-prospective transition method. Under the modified-prospective method, awards that are granted, modified, repurchased, or canceled after the date of adoption should be measured and accounted for in accordance with SFAS No. 123R. The unvested portion of awards that are granted prior to the effective date will be accounted for in accordance with SFAS No. 123. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R will have a significant impact on our financial statements. We do not expect SFAS No. 123R to significantly change recorded compensation expense related to grants of restricted Partnership units and restricted CEI shares. Had the Company adopted SFAS No. 123R in prior periods, we believe the impact of that standard would have approximated the impact of SFAS No. 123 as described in the “Stock-Based Employee Compensation” disclosure of pro forma net income and earnings per share. As of December 31, 2005, we had 0.7 million unit options and 50,000 CEI stock options outstanding that had not yet vested, with a remaining estimated fair value of $2.3 million and we had 0.2 million unvested restricted units and 0.2 million unvested restricted CEI shares with a remaining estimated fair value of $12.7 million. Based on these estimated fair values, we currently anticipate stock based compensation expense for 2006 will be $5.7 million.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154), which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005, and requires retrospective application to prior period financial statements of voluntary changes in accounting principle, unless it is impractical to determine either the period-specific effects or the cumulative effect of the change. The consolidated financial position, results of operations or cash flows will only be impacted by SFAS 154 if the Company implements a voluntary change in accounting principle or corrects accounting errors in future periods.
Disclosure Regarding Forward-Looking Statements
This report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may, ““believe, ““will, ““expect, ““anticipate, ““estimate, ““continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We have identified factors that could cause actual plans or results to differ materially from those included in any forward-looking statements. These factors include those described in “Item 1A. Risk Factors”, or in our other Securities and Exchange Commission filings, among others. Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks when you are evaluating us.
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. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership’s primary market risk is the risk related to changes in the prices of natural gas and natural gas liquids. In addition, it is also exposed to the risk of changes in interest rates on its floating rate debt.
Interest Rate Risk. We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2005, our variable rate debt had a carrying value of $322.7 million, which approximated the fair value, and our fixed rate debt had a carrying value of $200 million and an approximate fair value of $203.9 million. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate senior and subordinated debt.
The following table shows the carrying amount and fair value of long-term debt and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest rates increase or decrease.
(a)
Fair value is based upon current market quotes and is the estimated amount required to purchase our long-term debt on the open market. This estimated value does not include any redemption premium.
Commodity Price Risk. Approximately 7.5% of the natural gas the Partnership purchases for resale is purchased on a percentage of the relevant natural gas price index, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, the Partnership’s margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. The Partnership has hedged approximately 80% of its exposure to gas price fluctuations through the end of 2006.
Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of gas bought or sold under either basis, which leaves 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 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 risk on its 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 natural gas liquids 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.
The Partnership manages its price risk related to future physical purchase or sale commitments for its producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance its future commitments and significantly reduce its risk to the movement in natural gas prices. However, the Partnership is subject to counterparty risk for both the physical and financial contracts. The Partnership accounts for certain of its producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to its producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.
For each reporting period, we record the fair value of open energy trading contracts based in the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts which have been designated as cash flow hedges are also recorded in profit or loss on energy trading contracts. As of December 31, 2005, outstanding natural gas swap agreements, natural gas liquids swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value liability of $3.7 million, excluding the fair value asset of $5.1 million associated with the natural gas liquids puts. The aggregate effect of a hypothetical 10% increase in gas and natural gas liquids prices would result in a an increase of approximately $12.5 million in the net fair value liability of these contracts as of December 31, 2005. The value of the natural gas puts would also decrease as a result of an increase in natural gas liquids prices but we are unable to determine the impact of a 10% price change. Our maximum loss on these puts is the remaining $5.1 million cost for the puts.
Credit Risk. The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, its purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to the Partnership’s overall profitability.
Item 8.
Item 8.
Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages through of this Report and are incorporated herein by reference.
2Item 9.
Item 9A.
Controls and Procedures
(a)
Evaluation of Disclosure controls and procedures
We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the design and operating effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2005 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission. Because of inherent limitation in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.
(b) Changes in Internal control over financial reporting
There has been no change in our internal controls over financial reporting that occurred in the three months ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” on page.
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Executive Officers of the Registrant
The following table shows information about our executive officers. Executive officers serve until their successors are elected or appointed.
(1)
Not related.
Barry E. Davis, President, Chief Executive Officer and Director, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of our
predecessor. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis also serves as a director of Crosstex Energy GP, LLC, the general partner of the general partner of the Partnership. Mr. Davis holds a B.B.A. in Finance from Texas Christian University.
James R. Wales, Executive Vice President Commercial, joined our predecessor in December 1996. As one of the founders of Sunrise Energy Services, Inc., he helped build Sunrise into a major national independent natural gas marketing company, with sales and service volumes in excess of 600,000 MMBtu/d. Mr. Wales started his career as an engineer with Union Carbide. In 1981, he joined Producers Gas Company, a subsidiary of Lear Petroleum Corp., and served as manager of its Mid-Continent office. In 1986, he joined Sunrise as Executive Vice President of Supply, Marketing and Transportation. From 1993 to 1994, Mr. Wales was the Chief Operating Officer of Triumph Natural Gas, Inc., a private midstream business. Prior to joining Crosstex, Mr. Wales was Vice President for Teco Gas Marketing Company. Mr. Wales holds a B.S. degree in Civil Engineering from the University of Michigan, and a Law degree from South Texas College of Law.
A. Chris Aulds, Executive Vice President Public and Governmental Affairs, together with Barry E. Davis, participated in the management buyout of Comstock Natural Gas in December 1996. Mr. Aulds joined Comstock Natural Gas, Inc. in October 1994 as a result of the acquisition by Comstock of the assets and operations of Victoria Gas Corporation. Mr. Aulds joined Victoria in 1990 as Vice President responsible for gas supply, marketing and new business development and was directly involved in the providing of risk management services to gas producers. Prior to joining Victoria, Mr. Aulds was employed by Mobil Oil Corporation as a production engineer before being transferred to Mobil’s gas marketing division in 1989. There he assisted in the creation and implementation of Mobil’s third- party gas supply business segment. Mr. Aulds holds a B.S. degree in Petroleum Engineering from Texas Tech University.
Jack M. Lafield, Executive Vice President Corporate Development, joined our predecessor in August 2000. For five years prior to joining Crosstex, Mr. Lafield was Managing Director of Avia Energy, an energy consulting group, and was involved in all phases of acquiring, building, owning and operating midstream assets and natural gas reserves. He also provided project development and consulting in domestic and international energy projects to major industry and financing organizations, including development, engineering, financing, implementation and operations. Prior to consulting, Mr. Lafield held positions of President and Chief Executive Officer of Triumph Natural Gas, a private midstream business he founded, President and Chief Operating Officer of Nagasco, Inc. (a joint venture with Apache Corporation), President of Producers’ Gas Company, and Senior Vice President of Lear Petroleum Corp. Mr. Lafield holds a B.S. degree in Chemical Engineering from Texas A&M University, and is a graduate of the Executive Program at Stanford University.
William W. Davis, Executive Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has 25 years of finance and accounting experience. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President - Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant.
Joe A. Davis, Executive Vice President, General Counsel and Secretary, joined Crosstex in October 2005. Mr. Davis began his legal career with the Dallas firm of Worsham Forsythe, which merged with the international law firm of Hunton & Williams in 2002. Most recently, he served as a partner in the firm’s Energy Practice Group, and served on the firm’s Executive Committee. Mr. Davis specialized in facility development, sales, acquisitions and financing for the energy industry, representing entrepreneurial start up/development companies, growth companies, large public corporations and large electric and gas utilities. He received his J.D. from Baylor Law School in Waco and his bachelor of science from the University of Texas in Dallas.
Robert S. Purgason, Senior Vice President - Treating Division, joined Crosstex in October 2004 to lead the Treating Division. Prior to joining Crosstex, Mr. Purgason spent 19 years with Williams Companies in various senior
business development and operational roles. He was most recently Vice President of the Gulf Coast Region Midstream Business Unit. Mr. Purgason began his career at Perry Gas Companies in Odessa working in all facets of the treating business. Mr. Purgason received a B.S. degree in Chemical Engineering with honors from the University of Oklahoma.
Danny L. Thompson, Senior Vice President - Engineering and Operations, has held various leadership positions within the midstream energy industry. From March 2005 until August 2005 when he became an employee of Crosstex, he worked with Crosstex as a consultant. Prior to joining Crosstex, he worked for Cantera Natural Gas L.L.C. as vice president, operations and engineering and CMS Field Services as director of engineering and operations. Mr. Thompson holds a bachelor’s degree in chemical engineering from Texas A&I University in Kingsville, and he is a registered professional engineer in Texas.
Code of Ethics
We adopted a Code of Business Conduct and Ethics applicable to all of our employees, including all officers, and including our independent directors, who are not employees, with regard to company-related activities. The Code of Business Conduct and Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. The Code also incorporates our expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications. A copy of our Code of Business Conduct and Ethics will be provided to any person, without charge, upon request. Contact Denise LeFevre at 214-721-9245 to request a copy of a charter or send your request to Crosstex Energy, Inc., Attn: Denise LeFevre, 2501 Cedar Springs, Suite 100, Dallas, Texas 75201. If any substantive amendments are made to the Code of Business Conduct and Ethics or if we grant any waiver, including any implicit waiver, from a provision of the code to any of our executive officers and directors, we will disclose the nature of such amendment or waiver in a report on Form 8-K.
Other
The sections entitled “Election of Directors”, “Additional Information Regarding the Board of Directors” “Section 16(a) Beneficial Ownership Reporting Compliance” and “Stockholder Proposals and Other Matters” that appear in our proxy statement for the 2006 annual meeting of stockholders (the “2006 Proxy Statement”), set forth certain information with respect to our directors and with respect to reporting under Section 16(a) of the Securities Exchange Act of 1934, and are incorporated herein by reference.
Item 11.
Item 11.
Executive Compensation
The section entitled “Executive Compensation” that appears in the 2006 Proxy Statement sets forth certain information with respect to the compensation of our management, and, except for the report of the Compensation Committee of our board of directors on executive compensation and the information in such section under “Performance Graph” is incorporated herein by reference.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management
The sections entitled “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation - Equity Compensation Plan Information” that appear in the 2006 Proxy Statement set forth certain information with respect to securities authorized for issuance under equity compensation plans and the ownership of voting securities and equity securities of us, and are incorporated herein by reference.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The section entitled “Certain Relationships and Related Party Transactions” that appears in the 2006 Proxy Statement sets forth certain information with respect to certain relationships and related party transactions, and is incorporated herein by reference.
Item 14.
Item 14.
Principal Accounting Fees and Services
The section entitled “Auditors” that appears in the 2006 Proxy Statement sets forth certain information with respect to accounting fees and services, and is incorporated herein by reference.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
The following documents are filed as part of this report:
(a) Financial Statements and Schedules
(1) Financial Statements. See the Index to Financial Statements on page.
(2) Financial Statement Schedules. See Schedule I - Parent Company Statements on page and Schedule II - Valuation and Qualifying Accounts on Page.
(3) Exhibits.
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
*
Filed herewith.

As required by Item 14(a)(3), this exhibit is identified as a compensatory benefit plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 15th day of March 2006.
CROSSTEX ENERGY, INC.
By:
/s/ Barry E. Davis
Barry E. Davis,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
MANAGEMENT’S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Crosstex Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for Crosstex Energy, Inc. (the “Company”). As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of the Company’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.
The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorization of the Company’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls.
Based on this assessment, management has concluded that as of December 31, 2005, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
The Company acquired, through its interest in Crosstex Energy, L.P., CFS Louisiana Midstream Company and El Paso Dauphin Island Company, L.L.C. during 2005, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, any internal control evaluation over financial reporting associated with the CFS Louisiana Midstream Company and El Paso Dauphin Island Company, L.L.C.’s total assets of $488.2 and total revenues of $66.3 million included in the consolidated financial statements of Crosstex Energy, Inc. and subsidiaries as of and for the year ended December 31, 2005.
KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on management’s assessment of internal control over financial reporting, a copy of which appears on the next page of this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Crosstex Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Crosstex Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedules. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Crosstex Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations, and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Crosstex Energy, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2006, expressed an unqualified opinion on management’s assessment of, and the effective operations of, internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 13, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Crosstex Energy, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Crosstex Energy, Inc. (a Delaware corporation) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Crosstex Energy, Inc. (the Company) maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations (COSO).
The Company acquired, through its interest in Crosstex Energy, L.P., CFS Louisiana Midstream Company and El Paso Dauphin Island Company, L.L.C. during 2005, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, any internal control over financial reporting associated with CFS Louisiana Midstream Company and El Paso Dauphin Island Company, L.L.C.’s total assets of $488.2 million and total revenues of $66.3 million included in the consolidated financial statements of Crosstex Energy, Inc. and subsidiaries as of and for the year ended December 31, 2005. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of CFS Louisiana Midstream Company and El Paso Dauphin Island Company, L.L.C.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Crosstex Energy, Inc. and subsidiaries as of December 31, 2005, and 2004 and the related consolidated statements of operations, changes in stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 13, 2006 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 13, 2006
CROSSTEX ENERGY, INC.
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Changes in Stockholders’ Equity
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Comprehensive Income December 31, 2005, 2004 and 2003
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements
December 31, 2005 and 2004
1.
Organization and Summary of Significant Agreements:
(a) Description of Business
Crosstex Energy, Inc. (the “Company” and formerly Crosstex Energy Holdings Inc.), a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids, or NGLs. The Company connects the wells of natural gas producers in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas to a variety of markets. In addition, the Company purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.
(b) Ownership in CELP and Public Offering of the Company
On July 12, 2002, the Company formed Crosstex Energy, L.P. (herein referred to as “the Partnership” or “CELP”), a Delaware limited partnership. Crosstex Energy GP, L.P., a wholly owned subsidiary of the Company, is the general partner of the Partnership. The Company also owned 9,334,000 subordinated units and 666,000 common units in the Partnership through its wholly-owned subsidiaries on December 31, 2005 which represented 38.0% of the limited partner interests in the Partnership. In February 2006, 2,333,000 of the Company’s subordinated units held by the Company converted to common units. The Company’s current ownership of Partnership units is 7,001,000 subordinated units and 2,999,000 common units.
In January 2004, the Company completed an initial public offering of its common stock. In conjunction with the public offering, the Company converted all of its preferred stock to common stock, cancelled its treasury stock and made a two-for-one stock split, effected in the form of a stock dividend. The Company’s existing shareholders sold 2,306,000 common shares (on a post-split basis) and the Company issued 345,900 common shares (on a post-split basis) at a public offering price of $19.50 per common share. The Company received net proceeds of approximately $4.8 million from the common stock issuance. The Company’s existing stockholders also repaid approximately $4.9 million in stockholder notes receivable in connection with the public offering. As of December 31, 2005, Yorktown owns 23% of the Company’s outstanding common shares, Company management and directors own 13% of its common shares and the remaining 64% is held publicly.
(c) Basis of Presentation
The accompanying consolidated financial statements include the assets, liabilities and results of operations of the Company and its majority owned subsidiaries, including the Partnership because of the general partner relationship that CEI exercises over the Partnership. The Company proportionately consolidates the Partnership’s undivided 12.4% interest in a carbon dioxide processing plant acquired by the Partnership in June 2004 and its undivided 23.85% interest in a gas plant acquired by the Partnership in November 2005. In January 2004, the Company adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities (“FIN No. 46R”) and began consolidating its joint venture interest in Crosstex DC Gathering, J.V. as discussed more fully in Note 5. The consolidated operations are hereafter referred to collectively as the “Company.” All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for the prior years to conform to the current presentation.
2.
Significant Accounting Policies
(a) Management’s Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Company to make estimates and assumptions that affect the
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.
(b) Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
(c) Inventories
Our inventories of products consist of natural gas and natural gas liquids. We report these assets at the lower of cost or market.
(d) Property, Plant, and Equipment
Property, plant and equipment consists of intrastate gas transmission systems, gas gathering systems, industrial supply pipelines, natural gas liquids pipelines, natural gas processing plants, NGLs, fractionation plants, an undivided 12.4% interest in a carbon dioxide processing plant, and gas treating plants.
Other property and equipment is primarily comprised of computer software and equipment, furniture, fixtures, leasehold improvements and office equipment. Such items are depreciated over their estimated useful life of three to seven years. Property, plant and equipment is recorded at cost. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. During 2005 interest of $0.9 million was capitalized to the North Texas Pipeline fixed asset projects under SFAS No. 34. Depreciation is provided using the straight-line method based on the estimated useful life of each asset, as follows:
Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires long-lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the Company compares the net book value of the asset to the undiscounted expected future net cash flows. If an impairment has occurred, the amount of such impairment is determined based on the expected future net cash flows discounted using a rate commensurate with the risk associated with the asset. An impairment of $1.0 million was recorded in the year ended December 31, 2004. The impairment recorded in 2004 related to a processing plant owned directly by the Company. This plant had been inactive since late 2002 when the operator of the wells behind the plant cancelled its drilling plan for the area. An impairment on the contracts associated with the plant was recorded in 2002 but the value of the plant was not impaired because the Company intended to restart or relocate the plant. Drilling activity had increased in the area near the plant and processing margins improved during 2004. As a result, management decided to more fully evaluate the cost of restarting this idle plant. During 2004 management determined that it would be more commercially feasible to put a new plant at the plant site than to invest the capital necessary to restart the plant. If the Company does not restart the plant, our engineers estimate that the plant would receive very little, if any, value upon the sale of the plant. Therefore, the Company has impaired the full value of the plant during 2004 under SFAS No. 144.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. The Company’s 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
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
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. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which would require us to record an impairment of an asset.
(e) Goodwill and Intangibles
The Company has approximately $6.6 million of goodwill at December 31, 2005. During the formation of the Partnership in May 2001, $5.4 million of goodwill was created and later amortized by $0.5 million. Approximately $1.7 million of goodwill resulted from the Cardinal acquisition in May 2005. The original goodwill has been allocated to the Midstream segment and the goodwill resulting from the Cardinal acquisition is allocated to the Treating segment and is assessed at least annually for impairment. During the fourth quarter of 2005, the Company completed the annual impairment testing of goodwill in accordance with SFAS 142 Goodwill and Other Intangible Assets and no impairment was required.
Intangible assets consist of customer relationships. The November 2005 El Paso acquisition as discussed in Note (4) added $253.8 million of such intangibles. The intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from three to 15 years, equaling a weighted average amortization period for those customer relationships of 14.7 years. Such amortization was approximately $4.3 million, $1.2 million and $0.9 million for the years ended December 31, 2005, 2004 and 2003, respectively. As of December 31, 2005, accumulated amortization of intangible assets was $7.7 million.
The following table summarizes the Company’s estimated aggregate amortization expense for the next five years (in thousands):
(f) Other Assets
Unamortized debt issuance costs totaling $8.4 million as of December 31, 2005 are included in other assets net. Debt issuance costs are amortized into interest expense over the term of the related debt. Other assets net as of December 31, 2005 also includes the non-current portion of the note receivable from RLAC Gathering Group, L.P., the minority interest partner in the CDC joint venture discussed in Note 5.
(g) Gas Imbalance Accounting
Quantities of natural gas over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas. The Company had an imbalance payable of $30.5 million and $2.0 million at December 31, 2005 and 2004, respectively, which approximates the fair value for these imbalances. The Company had an imbalance receivable of $7.8 million and $0.6 million at December 31, 2005 and 2004, respectively, which are carried at the lower of cost or market value.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
(h) Revenue Recognition
The Company recognizes revenue for sales or services at the time the natural gas or NGLs are delivered or at the time the service is performed. See discussion of accounting for energy trading activities in note 2(i).
(i) Commodity Risk Management
The Company engages in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, oil and NGLs. To qualify as a hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statements of operations as a cost of gas purchased.
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), Accounting for Derivative Instruments and Hedging Activities. This standard requires recognition of all derivative and hedging instruments in the statements of financial position as either assets or liabilities and measures them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically.
Currently, some of the derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in other comprehensive income in stockholders’ equity and reclassified into earnings in the same period in which the hedged transaction closes. The asset or liability related to the derivative instruments is recorded on the balance sheet in fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.
Certain derivative financial instruments that qualify for hedge accounting are not necessarily designated as cash flow hedges. These financial instruments and their physical quantities are marked to market, and recorded on the balance sheet in fair value of derivative assets or liabilities with related earnings impact recorded in the period the transactions are entered into.
(j) Commercial Services
The Company conducts “off-system” gas marketing operations as a service to producers on systems that the Company does not own. The Company refers to these activities as part of Commercial Services. In some cases, the Company earns an agency fee from the producer for arranging the marketing of the producer’s natural gas. In other cases, the Company purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas.
The Company manages its price risk related to future physical purchase or sale commitments for its Commercial Services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance the Company’s future commitments and significantly reduce its risk to the movement in natural gas prices. However, the Company is subject to counterparty risk for both the physical and financial contracts. The Company’s energy trading contracts qualify as derivatives, and accordingly, the Company continues to use mark-to-market accounting for both physical and financial contracts of its Commercial Services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives under SFAS No. 133
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
and physical delivery contracts relating to the Company’s Commercial Services natural gas marketing activities are recognized in earnings as gain or loss on derivatives immediately.
For each reporting period, the Company records the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period, in addition to the net realized gains or losses on settled contracts, is reported as net gain or loss on derivatives in the statements of operations.
Margins earned on settled contracts from its commercial services activities included in profit (loss) on energy trading contracts in the consolidated statement of operations was $1.6 million, $2.2 million, and $2.3 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Energy trading contract volumes that were physically settled were as follows (in MMBTUs):
(k) Comprehensive Income
Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, unrealized gains and losses on marketable securities, foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on derivative financial instruments.
Pursuant to SFAS No. 133, the Company records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.
(l) Concentrations of Credit Risk
Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade accounts receivable and derivative financial instruments. Management believes the risk is limited as the Company’s customers represent a broad and diverse group of energy marketers and end users. In addition, the Company continually monitors and reviews credit exposure to its marketing counterparties and letters of credit or other appropriate security are obtained as considered necessary to limit the risk of loss. See Note 10 for further discussion. The Company records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Company had a reserve for uncollectible trade receivables as of December 31, 2005 and December 31, 2004 of $0.3 million and $0.1 million, respectively. The allowance for uncollectible receivables related to the Enron claim was written off against the receivable balance in 2004 pursuant to the Company’s allowed claim in Enron’s bankruptcy proceedings.
During 2005, Formosa Hydrocarbons contributed 10.6% of our consolidated revenues. Prior to 2005 Kinder Morgan was the Company’s primary customer, contributing 10.2% in 2004 and 20.5% in 2003. As the Company continues to grow and expand, this relationship between individual customer sales and consolidated total sales is expected to continue to change. While these customers represent a significant percentage of consolidated revenues, the loss of this customer would not have a material impact on our results of operations.
(m) Environmental Costs
Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that related to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
reasonably estimated. For the years ended December 31, 2005, 2004 and 2003, such expenditures were not significant.
(n) Option Plans
The Company applies the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), and the related interpretations in accounting for the plan. In accordance with APB No. 25 for fixed rate stock and unit options, compensation is recorded to the extent the fair value of the stock or unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. In addition, compensation expense is recorded for variable options based on the difference between fair value of the stock or unit and the exercise price of the options at the end of the period.
The Company will adopt SFAS No. 123R effective January 1, 2006 and apply the modified prospective transition method. Under this method awards that are granted, modified, repurchased or cancelled after the date of adoption should be measured and accounted for in accordance with SFAS No. 123R. Awards that are granted prior to the effective date should continue to be accounted for in accordance with SFAS No. 123 except that stock option expense for unvested options must be recognized in the income statement. We do not expect the impact on net income under SFAS No. 123R to materially differ from the amounts presented in pro forma net income under SFAS No. 123.
Stock based compensation expense of $4.1 million, $1.0 million and $5.3 million was recognized in 2005, 2004 and 2003, respectively. The portion of compensation expense for 2005 and 2004 related to operating activities was $0.4 million and $0.2 million, respectively, and the remaining expense for the respective years of $3.7 million and $0.8 related to general and administrative activities. The stock based compensation expense recorded in 2005 included $0.5 million related to the accelerated vesting of 7,060 Partnership unit options and 10,000 common share options and $1.5 million related to amortization of restricted Partnership units and restricted common shares. Stock based compensation expense for 2005 also includes $0.4 million of payroll taxes associated with common stock option exercises.
Had compensation cost for the Company been determined based on the fair value at the grant date for awards in accordance with SFAS No. 123, Accounting for Stock Based Compensation, the Company’s net income (loss) would have been as follows (in thousands except per share amounts):
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The fair value of each option is estimated on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions used for grants in 2005, 2004 and 2003:
No Company options were granted to employees, officers or directors during 2003.
(o) Sales of Securities by Subsidiaries
The Company recognizes gains and losses in the consolidated statements of operations resulting from subsidiary sales of additional equity interest including exercises of stock options and CELP limited partnership units, to unrelated parties as discussed in Note 3(a).
(p) Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R “Share-Based Payment,” which requires compensation related to all stock-based awards, including stock options be recognized in the consolidated financial statements. The provisions of SFAS No. 123R are effective for the first annual reporting period that begins after June 15, 2005. We will adopt this standard on January 1, 2006 and will elect the modified-prospective transition method. Under the modified-prospective method, awards that are granted, modified, repurchased, or canceled after the date of adoption should be measured and accounted for in accordance with SFAS No. 123R. The unvested portion of awards that are granted prior to the effective date will be accounted for in accordance with SFAS No. 123. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R will have a significant impact on our financial statements. We do not expect SFAS No. 123R to significantly change recorded compensation expense related to grants of restricted Partnership units and restricted CEI shares. Had we adopted SFAS No. 123R in prior periods, we believe the impact of that standard would have approximated the impact of SFAS No. 123 as described in the “Stock Based Employee Compensation” disclosure of pro forma net income and earnings per share. As of December 31, 2005, we had 0.7 million unit options and 50,000 CEI stock options outstanding that had not yet vested, with a remaining estimated fair value of $2.3 million and we had 0.2 million unvested restricted units and 0.2 million unvested restricted CEI shares with a remaining estimated fair value of $12.7 million. Based on these estimated fair values, we currently anticipate stock based compensation expense for 2006 will be $5.7 million.
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB Statement No. 143. FIN 47 is effective at December 31, 2005, and had no significant impact on the Partnership’s financial position or results of operations.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154) which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, and requires retrospective application to prior period financial statements of voluntary changes in accounting principle, unless it is impractical to determine either the period-specific effects or the cumulative effect of the change. The consolidated financial position, results of operations or cash flows will only be impacted by SFAS 154 if the Company implements a voluntary change in accounting principle or corrects accounting errors in future periods.
3.
Public Offerings of Units by CELP and Certain Provisions of the Partnership Agreement
(a) Issuance of Common Units, Senior Subordinated Units and Senior Subordinated Series B Units
Crosstex Energy, L.P.’s partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. Net income is allocated to the general partner based on incentive distributions, as described (e) below, earned for the period plus 2% of remaining net income. In June 2005, the Partnership amended its partnership agreement to allocate the expenses attributable to the Company’s stock options and restricted stock awarded to employers and directors of the Partnership all to the general partner to make the related general partner contribution.
In September 2003, the Partnership completed a public offering of 3,450,000 common units at a public offering price of $17.99 per common unit. The Partnership received net proceeds of approximately $59.2 million, including an approximate $1.3 million capital contribution by us in order to maintain our 2% interest. The net proceeds were used to repay borrowings outstanding under the bank credit facility of our operating partnership. As a result of this offering, we recognized a gain of $18.4 million due to the Partnership issuing additional units at prices per unit greater than our equivalent carrying value.
On June 24, 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $50.0 million, (excluding our general partner contribution). The senior subordinated units were issued at $33.44 per unit, which represents a discount of 13.7% to the market value of common units on such date, and 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. As a result of this offering, upon the conversion of these units to common units in the first quarter of 2006, we will recognize a gain of $19.1 million due to the Partnership issuing additional units at prices per unit greater than our equivalent carrying value.
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 $105.0 million, net of expenses associated with the sale (excluding our general partner contribution). 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. The Senior Subordinated Series B Units were not entitled to distributions paid on November 14, 2005. The net proceeds were used to fund a portion of the El Paso acquisition. As a result of this offering, we recognized a gain of $37.5 million due to the Partnership issuing additional units at prices per unit greater than our equivalent carrying value.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
In November and December 2005, the Partnership issued 3,731,050 additional common units to the public at a purchase price of $33.25 per unit. The offering resulted in net proceeds to the Partnership of approximately $118.4 million net of expenses associated with the offering, (excluding our general partner contribution). The net proceeds from this offering were used to fund a portion of the El Paso acquisition. As a result of this offering, we recognized a gain of $27.6 million due to the Partnership issuing additional units at prices per unit greater than our equivalent carrying value.
(b) Limitation on Issuance of Additional Common Units
During the subordination period, the Partnership may issue up to 2,633,000 additional common units or an equivalent number of securities ranking on parity with the common units without obtaining unitholder approval. The Partnership may also issue an unlimited number of common units during the subordination period for acquisitions, capital improvements or debt repayments that increase cash flow from operations per unit on a pro forma basis.
(c) Subordination Period
The subordination period will end once the Partnership meets the financial tests in the partnership agreement, but it generally cannot end before December 31, 2007 except as discussed in (d) below. When the subordination period ends, each remaining subordinated unit will convert into one common unit and the common units will no longer be entitled to arrearages.
(d) Early Conversion of Subordinated Units
If the Partnership meets the applicable financial tests in the partnership agreement for the three consecutive four-quarter periods ending on December 31, 2005 or December 31, 2006, up to 4,666,000 of the subordinated units may be converted into common units prior to December 31, 2007. Because the Partnership met the financial tests for three consecutive four-quarter periods ended December 31, 2005, 2,333,000 subordinated units converted to common units upon the payment of the fourth quarter distribution on February 15, 2006. If the Partnership meets these tests for the three consecutive four-quarter periods ending on or after December 31, 2006, an additional 2,333,000 of the subordinated units will convert to common units.
(e) Cash Distributions
In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter commencing with the quarter ending on March 31, 2003. Distributions will generally be made 98% to the common and subordinated unit-holders and 2% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The Partnership’s senior secured credit facility prohibits the Partnership from declaring distributions to unitholders if any event of default exists or would result from the declaration of distributions. See Note (6) for a description of the bank credit facility covenants.
Under the quarterly incentive distribution provisions, generally its general partner is entitled to 13% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48% of amounts the Partnership distributes in excess of $0.375 per unit. Incentive distributions totaling $10.7 million and $5.6 million were earned by the Company for the years ended December 31, 2005 and 2004, respectively. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter. The Partnership paid annual per common unit distributions of $1.93, $1.70, and $1.25 for the years ended December 31, 2005, 2004 and 2003, respectively.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
4.
Significant Asset Purchases and Acquisitions
On June 30, 2003, the Partnership completed the acquisition of certain assets from Duke Energy Field Services, L.P. for $68.1 million, including the effect of certain purchase price adjustments. The assets acquired included: the Mississippi pipeline system, a 12.4% interest in the Seminole gas processing plant, the Conroe gas plant and gathering system, the Alabama pipeline system and two small gathering systems in Louisiana. The Company has accounted for this acquisition as a business combination in accordance with SFAS No. 141, Business Combinations. The Company has utilized the purchase method of accounting for this acquisition with an acquisition date of June 30, 2003.
In April 2004, the Partnership acquired, through its wholly-owned subsidiary Crosstex Louisiana Energy, L.P., the LIG Pipeline Company and its subsidiaries (LIG Inc., Louisiana Intrastate Gas Company, L.L.C., LIG Chemical Company, LIG Liquids Company, L.L.C. and Tuscaloosa Pipeline Company) (collectively, “LIG”) from American Electric Power (“AEP”) in a negotiated transaction for $73.7 million. LIG consists of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to south and southeast Louisiana. The Partnership financed the acquisition through borrowings under its amended bank credit facility.
The Partnership utilized the purchase method of accounting for this acquisition with an acquisition date of April 1, 2004. The purchase price and our allocation thereof are as follows (in thousands):
Intangible assets relate to customer relationships and are amortized over three years. The Company also increased its deferred tax liability by $0.9 million during 2004 because the LIG acquisition caused the Company’s estimated future tax rate to increase from 35% to 36.4% due to the effect of state taxes in Louisiana.
In November 2005, the Partnership acquired El Paso Corporation’s processing and natural gas liquids business in south Louisiana for $481.0 million. The assets acquired include 2.3 billion cubic feet per day of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines. The Partnership financed the acquisition with net proceeds totaling $228.0 million from the issuance of common units and Senior Subordinated Series B Units (including the 2% general partner contributions totaling $4.7 million) and borrowings under its bank credit facility for the remaining balance.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The Partnership has utilized the purchase method of accounting for this acquisition with an acquisition date of November 1, 2005. The purchase price and our allocation thereof are as follows (in thousands):
Intangible assets relate to customer relationships and are being amortized over 15 years. The Company also increased its deferred tax liability by $0.6 million during 2005 because the El Paso acquisition caused the Company’s estimated future tax rate to increase from 36.4% to 37.1% due to the effect of state taxes in Louisiana.
The preliminary purchase price allocation for the El Paso acquisition has not been finalized because the Partnership is still in the process of finalizing working capital settlements with El Paso Corporation and estimating potential contingent obligations associated with the assets acquired.
Operating results for the LIG assets and El Paso assets have been included in the Statements of Operations since April 1, 2004 and November 1, 2005, respectively. The following unaudited pro forma results of operations assume that the LIG acquisition and the El Paso acquisition occurred on January 1, 2004 (in thousands, except per unit amounts):
5.
Investment in Limited Partnerships and Note Receivable
The Partnership owns a 50% interest in Crosstex Denton County Gathering, J.V. (“CDC”). Prior to 2004, the Partnership accounted for its investment in CDC under the equity method. Under this method, the Partnership carried its investments at cost and recorded its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them were recorded as a reduction in the Partnership’s investment in the affiliated partnership. In January 2004, the Partnership began consolidating its investment in CDC pursuant to FIN No. 46R.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
In connection with the formation of CDC, the Partnership agreed to loan the CDC Partner up to $1.5 million for their initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC Partner’s 50% share of distributable cash flow to repay the loan. Any balance remaining on the note is due in August 2007 in the accompanying consolidated balance sheet. The current portion of loan receivable of $0.8 million from the CDC partner is included in notes receivable as of December 31, 2005. The remaining balance of $0.4 million is included in other assets, net as of December 31, 2005.
Until December 31, 2004, the Partnership owned a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Partners, L.P. (“CPP”) and a 20.31% interest as a limited partner in CPP. The Company accounted for its investment in CPP under the equity method for the years ended December 31, 2002, 2003 and 2004 because it exercised significant influence in operating decisions as a general partner in CPP.
Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of CPP for $5.1 million. This acquisition makes the Partnership the sole limited partner and general partner of CPP, so the Partnership began consolidating its investment in CPP effective December 31, 2004.
6.
Long-Term Debt
As of December 31, 2005 and 2004, long-term debt consisted of the following (in thousands):
Credit Facility. In 2005 the Partnership amended its $200 million senior secured credit facility to increase the credit facility to provide for $750 million at any one time outstanding and the issuance of letters of credit in the aggregate face amount of up to $300 million at any one time.
The facility was used to finance a portion of the El Paso acquisition and will be used to finance the acquisition and development of gas gathering, treating, and processing facilities, as well as working capital, letters of credit, distributions and other general partnership purposes. At December 31, 2005, $407.0 million was outstanding under the facility, including $85.0 million of letters of credit, leaving approximately $343.0 million available for future borrowings. The facility will mature in March 2010, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the credit facility may be re-borrowed.
Obligations under the credit facility are secured by first priority liens on all of CELP’s material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of its equity interests in certain of its subsidiaries, and ranks pari passu in right of payment with the senior secured notes. The credit agreement is guaranteed by certain of its subsidiaries. CELP 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 CELP’s option at the administrative agent’s reference rate plus 0% to 0.50% or LIBOR plus 1.00% to 2.00%. The applicable margin varies quarterly based on
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
our leverage ratio. The fees charged for letters of credit range from 1.00% to 2.00% per annum, plus a fronting fee of 0.125% per annum. CELP will incur quarterly commitment fees based on the unused amount of the credit facilities.
The credit agreement prohibits CELP 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:
•
incur indebtedness;
•
grant or assume liens;
•
make certain investments;
•
sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
•
make distributions;
•
change the nature of the Partnership’s business;
•
enter into certain commodity contracts;
•
make certain amendments to the Partnership’s agreement; and
•
engage in transactions with affiliates.
The credit facility contains the following covenants requiring the Partnership to maintain:
•
a maximum ratio of total funded debt to consolidated earnings before interest, taxes, depreciation and amortization (each as defined in the credit agreement), measured quarterly on a rolling four-quarter basis, (i) 5.25 to 1.00 for any fiscal quarter ending during the period commencing on the effective date of the credit facility and ending March 31, 2006, (ii) 4.75 to 1.00 for any fiscal quarter ending during the period commencing on April 1, 2006, and (iii) 4.00 to 1.00 for any fiscal quarter ending thereafter, pro forma for any asset acquisitions (but during an acquisition adjustment period (as defined in the credit agreement), the maximum ratio is increased to 4.75 to 1); and
•
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:
•
failure to pay any principal, interest, fees, expenses or other amounts when due;
•
failure to observe any agreement, obligation, or covenant in the credit agreement, subject to cure periods for certain failures;
•
certain judgments against us or any of our subsidiaries, in excess of certain allowances;
•
certain ERISA events involving the Partnership or its subsidiaries;
•
a change in control (as defined in the credit agreement); and
•
the failure of any representation or warranty to be materially true and correct when made.
Senior Secured Notes. In June 2003, the Partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million aggregate principal amount of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, the Partnership issued $10.0 million aggregate principal amount of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years. In June 2004, the master shelf agreement was amended, increasing the amount issuable under the agreement from $50.0 million to $125.0 million. In June 2004, the Partnership issued $75.0 million aggregate principal amount of senior secured notes with an interest rate of 6.96% and a maturity
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
of ten years. In June 2005, the master shelf agreement was amended, increasing the amount issuable under the agreement from $125.0 million to $200.0 million. In November 2005, the Partnership issued an $85.0 million aggregate principal amount of senior secured notes with an interest rate of 6.23% and a maturity of ten years.
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 the Partnership’s subsidiaries.
The initial $40.0 million of senior secured notes are redeemable, at CELP’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 $75.0 million senior secured notes issued in June 2004 and the $85.0 million issued in November 2005 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.
The master shelf agreement relating to the notes contains substantially the same covenants and events of default as the bank credit facility.
If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of at least 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to the nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable.
The Partnership was in compliance with all debt covenants at December 31, 2005 and 2004.
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.
Other Note Payable. In June 2002, as part of the purchase price of Florida Gas Transmission Company (FGTC), the Partnership issued a note payable for $.8 million to FGTC that is payable in $.1 million annual increments through June 2006 with a final payment of $1.6 million due in June 2007. The note bears interest payable annually at LIBOR plus 1%.
Maturities: Maturities for the long-term debt as of December 31, 2005 are as follows (in thousands):
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
7.
Income Taxes
The Company provides for income taxes using the asset and liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis that will reverse in future periods (in thousands).
A reconciliation of the provision for income taxes is as follows (in thousands):
The principal components of the Company’s net deferred tax liability are as follows (in thousands):
At December 31, 2005, the Company had a net operating loss carryforward of approximately $33.6 million that expires from 2021 through 2025. The Company also has various state net operating loss carryforwards of approximately $7.3 million which will begin expiring in 2016. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
carryforwards before they expire. Although the Company has generated net operating losses in the past and the Company expects to have significant amounts of future taxable income from its investment in the Partnership, through which the Company will receive remedial allocations of income among the unitholders and the special allocation of income based on the Company’s incentive distribution rights.
Deferred tax liabilities relating to property, plant, equipment and intangible assets represent, primarily, the Company’s share of the book basis in excess of tax basis for assets inside of the Partnership. The Company has also recorded a deferred tax asset in the amount of $5.8 million relating to the difference between its book and tax basis of its investment in the Partnership. Because the Company can only realize this deferred tax asset upon the liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. The deferred tax asset and the related valuation allowance increased $1.5 million from 2004 to 2005 due to the increase in the future expected tax rate from 36.4% in 2004 to 37.1% in 2005 and the issuance of Partnership common units and the deemed contribution for stock options. The increase in the future expected tax rate was directly related to the provision for the effect of state taxes on the November 2005 El Paso acquisition.
8.
Retirement Plans
The Company sponsors a single employer 401(k) plan for employees who become eligible upon the date of hire. The Partnership made year-end discretionary contributions to the plan of $0.3 million for the year ended December 31, 2003. During 2004 the Partnership amended the plan to allow for contributions to be made at each compensation calculation period based on the annual discretionary contribution rate. Contributions to the plan for the years ended December 31, 2005 and December 31, 2004 were $0.6 million and $0.5 million, respectively.
9.
Employee Incentive Plans
(a) Long-Term Incentive Plan
In December 2002, the Partnership adopted a long-term incentive plan for its employees, directors, and affiliates who perform services for the Partnership. The plan currently permits the grant of awards covering an aggregate of 2,600,000 common unit options and restricted units. The plan is administered by the compensation committee of the Partnership’s board of directors.
(b) Restricted Units
A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Compensation Committee, cash equivalent to the value of a common unit. In addition, the restricted units will become exercisable upon a change of control of the Partnership, its general partner, or the Company.
The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive and the Partnership will receive no remuneration for the units.
Restricted units totaling 98,150 and 163,934 were issued in 2003 and 2005, respectively, to senior management and directors with an intrinsic value equal to $1.3 million and $6.0 million, respectively. The units issued in 2003 vest over a five-year period and the units issued in 2005 vest over a three-year period. The intrinsic value of the units will be amortized into stock-based compensation over the vesting period. The Partnership recognized stock-based compensation expense of $1.2 million, $0.3 million and $0.2 million related to the amortization of these restricted units in 2005, 2004 and 2003, respectively.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
(c) Partnership Unit Options
Unit options will have an exercise price that, in the discretion of the compensation committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, unit options will become exercisable upon a change in control of the Partnership, or its general partner, or the Company.
A summary of the unit option activity for the years ended December 31, 2005, 2004 and 2003 is provided below:
The following table summarizes information about outstanding options as of December 31, 2005:
The Partnership currently accounts for option grants in accordance with APB No. 25, Accounting for Stock issued to Employees and follows the disclosure only provision of SFAS No. 123, Accounting for Stock-based Compensation. The Partnership will adopt SFAS No. 123R effective January 1, 2006 and apply the modified prospective transition method. Under this method awards that are granted, modified, repurchased, or canceled after the date of adoption should be measured and accounted for in accordance with SFAS No. 123R. The unvested portion of awards that are granted prior to the effective date will be accounted for in accordance with SFAS No. 123. In September 2003, two directors elected to receive options to purchase 10,752 common units (in aggregate) in the Partnership for their 2003 annual director fees. The options vest over a three-year period with an exercise price of
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
$11.63 per common unit. Since the exercise price was below the market price on the grant date, the Company recorded stock-based compensation of $27,000 in 2003 to recognize the vesting of a portion of such options during 2003.
(d) Crosstex Energy, Inc.’s Option Plan and Restricted Stock
The Company has one stock-based compensation plan, the Crosstex Energy, Inc. Long-Term Incentive Plan. The plan currently permits the grant of awards covering an aggregate of 1,200,000 options for common stock and restricted shares. The plan is administered by the compensation committee of the Company’s board of directors.
The Company applies the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), and the related interpretations in accounting for the plan. In accordance with APB No. 25 for fixed rate options, compensation is recorded to the extent the fair value of the stock exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. The Company will adopt SFAS No. 123R effective January 1, 2006 and apply the modified prospective transition method. Under this method awards that are granted, or canceled after the date of adoption should be measured and accounted for in accordance with SFAS No. 123R. Awards that are granted prior to the effective date should continue to be accounted for in accordance with SFAS No. 123 except that stock option expense for unvested options must be recognized in the income statement.
Compensation expense related to options for which variable accounting is required is recorded for variable options based on the difference between fair value of the stock or unit and exercise price of the options at period end. Compensation expense of $47,000 and $5.0 million was recognized in 2004 and 2003, respectively, related to the Company’s stock options. As discussed below, the Company modified certain options during 2003 which accounted for using variable accounting.
A summary of the status of the 2000 Stock Option Plan as of December 31, 2005, 2004 and 2003, is presented in the table below (all amounts have been adjusted to reflect the two-for-one stock split made by the Company in connection with its January 2004 initial public offering):
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The following table summarizes information about outstanding options as of December 31, 2005:
The Company modified certain outstanding options attributable to its common shares in the first quarter of 2003, which allowed the option holders to elect to be paid in cash for the modified options based on the fair value of the options. The total number of its options which have been modified is approximately 364,000. These modified options were accounted for using variable accounting as of the option modification date. The Company accounted for the modified options as variable options until the holders elected to cash out the options or the election to cash out the options lapsed. The Company was responsible for paying the intrinsic value of the options for the holders who elected to cash out their options. December 31, 2003 was the last valuation date that a holder of modified options could elect the cash-out alternative. Accordingly, effective January 1, 2004, the Company ceased applying variable accounting to the remaining modified options. The Company recognized stock-based compensation expense of approximately $5.0 million related to the variable options for the year ended December 31, 2003.
Restricted shares in the Company were issued to members of management under its long-term incentive plan in 2003 and 2005. The Company issued 124,880 restricted shares in 2005 and 85,000 in 2003 with an intrinsic value of $6.6 million and $2.4 million, respectively. Vesting of 80,000 of the Company restricted shares is over a five-year period and 129,880 of the restricted shares vest over a three-year period. The intrinsic value of the restricted shares is amortized into stock-based compensation expense over the vesting periods.
(e) Earnings per share and anti-dilutive computations
Basic earnings per common share was computed by dividing net income by the weighted-average number of common shares outstanding for the periods presented. The computation of diluted earnings per common share further assumes the dilutive effect of common share options and restricted shares.
In conjunction with the Company’s initial public offering in January 2004, the Company effected a two-for-one split. All share amounts for prior periods presented herein have been restated to reflect this stock split.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The following are the share amounts used to compute the basic and diluted earnings per share for the years ended December 31, 2005, 2004 and 2003 (in thousands, except per-share amounts):
All outstanding common shares were included in the computation of diluted earnings per common share.
10.
Fair Value of Financial Instruments
The estimated fair value of the Company’s financial instruments has been determined by the Company using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Company could realize upon the sale or refinancing of such financial instruments (in thousands):
The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. The carrying amount of the account receivable from Enron approximates the fair value based on the estimated recoverable value for our claim in their bankruptcy proceedings as discussed in Note 11. The carrying value for the note receivable approximates the fair value because this note earns interest based on the current prime rate.
The Partnership’s long-term debt was comprised of borrowings under a revolving credit facility totaling $322.0 million and $33.0 million as of December 31, 2005 and 2004, respectively, which accrues interest under a floating interest rate structure. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of December 31, 2005, the Company also had borrowings totaling $200 million under senior secured notes with a weighted average interest rate of 6.64%. The fair value of these
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
borrowings as of December 31, 2005 and 2004 were adjusted to reflect to current market interest rate for such borrowings as of December 31, 2005 and 2004.
The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction.
11.
Derivatives
The Company manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge prices and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.
The Partnership commonly enters into various derivative financial transactions which it does not designate as hedges. These transactions include “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, and “storage swaps”. Swing swaps are generally short-term in nature (one month), and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Third party on-system financial swaps are hedges that the Partnership enters into on behalf of its customers who are connected to its systems, wherein the Partnership fixes a supply or market price for a period of time for its customers, and simultaneously enters into the derivative transaction. Marketing financial swaps are similar to on-system financial swaps, but are entered into for customers not connected to the Partnership’s systems. Storage swaps transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements.
In August 2005 the Partnership acquired puts, or rights to sell a portion of the liquids from the plants at a fixed price over a two-year period beginning January 1, 2006 for a premium of $18.7 million, as part of the overall risk management plan related to the acquisition of the El Paso assets which closed on November 1, 2005. In December 2005 the Partnership sold a portion of these puts for $4.3 million. The Partnership did not designate these put options to obtain hedge accounting as of December 31, 2005 and therefore, these put options did not qualify as hedges as of December 31, 2005 and were marked to market through our consolidated statement of operations. The puts represent options, but not obligations, to sell the related underlying liquids volumes at a fixed price. As the price of the underlying liquids increased significantly in the period, the value of the put options declined and is reflected in gain/loss on derivatives.
The components of gain (loss) on derivatives in the Consolidated Statements of Operations are (in thousands):
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The fair value of derivative assets and liabilities, excluding the interest rate swap, are as follows (in thousands):
Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2005 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than October 2009. The Company’s counterparties to derivative contracts include BP Corporation, Total Gas & Power and J. Aron & Co., a subsidiary of Goldman Sachs. Changes in the fair value of the Partnership’s derivatives related to third-party producers and customers gas marketing activities are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings and the ineffective portion is recorded in earnings.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
On all transactions where the Company is exposed to counterparty risk, the Company analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits, and monitors the appropriateness of these limits on an ongoing basis.
Impact of Cash Flow Hedges
Natural Gas
For the year ended December 31, 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $7.0 million. For the year ended December 31, 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.9 million. As of December 31, 2005, an unrealized pre-tax derivative fair value loss of $0.8 million (net of minority interest and taxes), related to cash flow hedges of gas price risk, was
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
recorded in accumulated other comprehensive income (loss). This entire fair value loss is expected to be reclassified into earnings through December 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.
The settlement of futures contracts and basis swap agreements related to January 2006 gas production reduced gas revenue by approximately $0.7 million.
Liquids
For the year ended December 31, 2005, net losses on liquids swap hedge contracts decreased liquids revenue by approximately $1.2 million. For the year ended December 31, 2005, an unrealized pre-tax derivative fair value gain of $0.4 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). This entire fair value gain is expected to be reclassified into earnings in 2006 and in 2007. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.
Assets and liabilities related to third party derivative contracts, swing swaps, storage swaps and puts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded on a net basis as gain (loss) on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):
Account Receivable from Enron
On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. The Company has allowed unsecured claims in the Enron bankruptcy matter which total approximately $7.8 million. The Company wrote these claims down to $1.3 million at December 31, 2004, which is the estimate of recoverable value pursuant to the bankruptcy plan as confirmed by the bankruptcy court in July 2004. During the year ending December 31, 2005, we received payments on the Enron receivable in the amount of $0.2 million.
12.
Transactions with Related Parties
Camden Resources, Inc.
The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. (Camden). Camden is an affiliate of the Partnership by way of equity investments made by Yorktown in Camden. During the years ended December 31, 2005, 2004 and 2003, the Partnership purchased natural gas from Camden in the amount of approximately $67.2 million, $38.4 million and $8.4 million, respectively, and received approximately $2.6 million, $2.4 million and $0.2 million in treating fees from Camden.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
Crosstex Pipeline Partners, L.P.
Prior to December 31, 2004, the Partnership was the general partner and a limited partner in CPP as discussed in Note 5. The Partnership had related-party transactions with CPP, as summarized below:
•
During the years ended December 31, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $11.6 million and $8.2 million and paid for transportation of approximately $51,000 and $41,000, respectively, to CPP.
•
During the years ended December 31, 2004 and 2003, the Partnership received a management fee from CPP in the amount of approximately $125,000 and $125,000, respectively.
•
During the years ended December 31, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $159,000 and $104,000, respectively.
Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of the CPP Partnership for $5.1 million. This acquisition makes the Partnership the sole limited partner and general partner of CPP, so the Partnership began consolidating its investment in CPP effective December 31, 2004.
13.
Commitments and Contingencies
(a) Leases - Lessee
The Partnership has operating leases for office space, office and field equipment and the Eunice plant. The Eunice plant operating lease acquired in the El Paso acquisition provides for annual lease payments of $12.19 million with a lease term extending to November 20, 2012. At the end of the lease term the Partnership has the option to purchase the plant for $66.25 million.
The following table summarizes our remaining non-cancelable future payments under operating leases for leased office space and office and field equipment with initial or remaining non-cancelable lease terms in excess of one year (in millions):
Operating lease rental expense for the years ended December 31, 2005, 2004 and 2003 was approximately $3.4 million, $2.8 million and $1.8 million, respectively.
(b) Leases - Lessor
During 2005 the Company leased approximately 32 of its treating plants and 24 of its dewpoint control plants to customers under operating leases. The initial terms on these leases are generally 24 months at which time the leases revert to 30-day cancelable leases. As of December 31, 2005, the Company only had five treating plants under operating leases with remaining non-cancelable lease terms in excess of one year. The future minimum lease rentals are $1.6 million and $0.4 million for the years ended December 31, 2006 and 2007, respectively. These leased treating plants have a cost of $9.7 million and accumulated depreciation of $0.9 million as of December 31, 2005.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
(c) Employment Agreements
Certain members of management of the Company are parties to employment contacts with the general partner. The employment agreements provide each member of senior management with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.
(d) Environmental Issues
The Partnership acquired El Paso Corporation’s processing and natural gas liquid business in south Louisiana 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. The estimated remediation costs are expected to be approximately $0.3 million. 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. Contamination from historical operations has been identified at a number of sites within the acquired properties. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third-party company that specializes in remediation work. The Company does not expect to incur any material liability with these sites. The Partnership has disclosed these deficiencies to Louisiana Department of Environmental Quality and is working with the department to correct permit conditions and address modifications to facilities to bring them into compliance. The Company does not expect to incur any material environmental liability associated with these issues.
The Partnership acquired assets from DEFS in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of the Conroe site. Moreover, 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.
(e) Other
The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.
14.
Capital Stock
(a) Common Stock
The Company has authorized 19,000,000 shares of common stock at $.01 par value. At December 31, 2005 and 2004 the Company had 12,760,158 and 12,256,890 shares, respectively, issued and outstanding. In January 2004, the Company made a two-for-one stock split in conjunction with its initial public offering discussed in Note 1(b).
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
The Company paid annual common dividends of $1.69, $1.37, and $0 per share for the years ended December 31, 2005, 2004 and 2003, respectively.
(b) Notes Receivable
In January 2004, $4.9 million in stockholder notes receivable were repaid in conjunction with the Company’s initial public offering discussed in Note 1(b) and the remaining notes receivable were repaid in December 2004.
15.
Segment Information
Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Company’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Company’s natural gas gathering and transmission operations and includes the Mississippi System, the Conroe System, the Gulf Coast System, the Corpus Christi System, the Gregory gathering system located around the Corpus Christi area, the Arkoma System in Oklahoma, the Vanderbilt System located in south Texas, the LIG pipelines and processing plants located in Louisiana, the south Louisiana processing and liquids assets, and various other small systems. Also included in the Midstream division are the Company’s Producer Services operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. Included in the Treating division are four gathering systems that are connected to the treating plants and the Seminole plant located in Gaines County, Texas. During 2004, management decided that the Seminole plant, which was acquired in June 2003, should be included in the Treating division. Therefore, the 2003 segment information has been adjusted to reflect this reclassification.
The accounting policies of the operating segments are the same as those described in note 2 of the Notes to Consolidated Financial Statements. The Company evaluates the performance of its operating segments based on earnings before gain on issuance of units by CELP, income taxes, interest of non-controlling partners in CELP’s net income and accounting changes, and after an allocation of corporate expenses. Corporate expenses and stock-based compensation are allocated to the segments on a pro rata basis based on the number of employees within the segments. Interest expense is allocated on a pro rata basis based on segment assets. Intersegment sales are at cost.
Summarized financial information concerning the Company’s reportable segments is shown in the following table. There are no other significant non-cash items.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements - (Continued)
(a)
Midstream profit is net of a non-cash derivative loss of $10.2 million.
16.
Subsequent Event
Hanover Acquisition. On February 1, 2006, we acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.5 million. After this acquisition we have approximately 150 treating plants in operation and a total fleet of approximately 190 units.
17.
Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data is presented below.
SCHEDULE I
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED BALANCE SHEETS
See “Notes to Consolidated Financial Statements” of Crosstex Energy, Inc. included in this report.
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF OPERATIONS
See “Notes to Consolidated Financial Statements” of Crosstex Energy, Inc. included in this report.
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOW
See “Notes to Consolidated Financial Statements” of Crosstex Energy, Inc. included in this report.
SCHEDULE II
CROSSTEX ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS
(a)
Allowance for doubtful receivables on energy trading contracts related to natural gas marketing, substantially all of which relates to estimated losses from Enron claims. See Note 11 to Consolidated Financial Statements.
(b)
The allowance for doubtful receivables for the Enron claims was written off against the receivable balance in 2004 pursuant to the Company’s allowed claim in Enron’s bankruptcy proceedings.
EXHIBIT INDEX
*
Filed herewith.

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