Item 1. Business
General
Crosstex Energy, Inc. is a Delaware corporation, formed in April 2000. We completed our initial public offering in January 2004. Our shares of common stock are listed on the NASDAQ National Market under the symbol "XTXI". Our executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our telephone number is (214) 953-9500. In this report, the terms "Crosstex Energy, Inc." as well as the terms "our," "we," and "us," or like terms are sometimes used as references to Crosstex Energy, Inc. and its consolidated subsidiaries. References in this report to "Crosstex Energy, L.P.," the "Partnership," or like terms refer to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. and its consolidated subsidiaries.
CROSSTEX ENERGY, INC.
Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas. These partnership interests consist of the following:
•333,000 common units and 4,667,000 subordinated units, representing a 54.3% limited partner interest in the Partnership; and
•100% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.
Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership's business or to provide for future distributions.
The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.50 for that quarter, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter.
The following table sets forth the distributions we received from the Partnership since its initial public offering in December 2002.
(1)Reflects the pro rata minimum quarterly distribution covering the period from the closing of the Partnership's initial public offering on December 17, 2002 through December 31, 2002. This distribution was paid to us together with the March 31, 2003 distribution. We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:
•federal income taxes, which we are required to pay because we are taxed as a corporation;
•the expenses of being a public company;
•other general and administrative expenses;
•capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner's 2.0% general partner interest; and
•reserves our board of directors believes prudent to maintain, including reserves equal to the benefit we will receive in 2004 from our existing net operating loss carryforwards.
If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions.
Our ability to pay dividends is limited by the Delaware General Corporation Law, which provides that a corporation may only pay dividends out of existing "surplus," which is defined as the amount by which a corporation's net assets exceeds its stated capital. While our ownership of the general partner and the common and subordinated units of the Partnership are included in our calculation of net assets, the value of these assets may decline to a level where we have no "surplus," thus prohibiting us from paying dividends under Delaware law.
The Partnership's strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas, improving the profitability of its assets by increasing their utilization while controlling costs and pursuing new construction or expansion opportunities in its core operating areas. If the Partnership is successful in implementing this strategy, we believe the total amount of cash distributions it makes
will increase and our share of those distributions will also increase. The Partnership announced increases in its quarterly distribution two times since its initial public offering in December 2002. During that time, the Partnership increased the per unit quarterly cash distribution on its common and subordinated units by 40.0%, from $0.50 to $0.70. If the Partnership increased its per unit quarterly distribution to $0.80, its total quarterly distribution would increase $1,504,167 and we would receive $1,101,667, or 73.2%, of that increase. If Crosstex Energy, L.P. then issued an additional 1,000,000 units and maintained its per unit quarterly distribution at $0.80 per unit, its total quarterly distribution would increase another $923,930 and we would receive $123,930, or 13.4%, of that increase, assuming the general partner made a capital contribution to the Partnership sufficient to maintain its 2.0% general partner interest.
So long as we own the general partner, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of a majority of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. The Partnership may elect to forego an opportunity for several reasons, including:
•the nature of some or all of the target's assets or income might affect the Partnership's ability to be taxed as a partnership for federal income tax purposes;
•the board of directors of Crosstex Energy GP, LLC may conclude that some or all of the target assets are not a good strategic opportunity for the Partnership; or
•the seller may desire equity, rather than cash, as consideration and may not want to accept the Partnership's units as consideration.
We have no present intention of engaging in additional operations or pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement, although we may decide to pursue them in the future, either alone or in combination with the Partnership. In the event that we pursue the types of opportunities that we are permitted to pursue under the omnibus agreement, our board of directors, in its sole discretion, may retain all, or a portion of, the cash distributions we receive on our partnership interests in the Partnership to finance all, or a portion of, such transactions, which may reduce or eliminate dividends paid to our stockholders.
CROSSTEX ENERGY, L.P.
Crosstex Energy L.P. is a rapidly growing independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas. The Partnership connects the wells of natural gas producers in its market areas to its gathering systems, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generates gross margins based on the difference between the purchase and resale prices. In addition, the Partnership purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.
The Partnership's major assets include over 2,500 miles of natural gas gathering and intrastate transmission pipelines, three natural gas processing plants connected to its gathering systems with a total NGL production capacity of 289,800 gallons per day and 61 natural gas treating plants. The Partnership's recently announced acquisition of LIG Pipeline Company (LIG) will add 2,000 miles of
pipeline and three major processing plants to the Partnership's assets. The Partnership's gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership's processing plants remove NGLs from a natural gas stream and fractionate, or separate, the NGLs into separate NGL products, including ethane, propane, mixed butanes and natural gasoline. The Partnership's natural gas treating plants, located largely in the Texas Gulf Coast area, remove impurities from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications.
Set forth in the table below is a list of the Partnership's significant acquisitions since January 2000.
(1)Certain Gulf Coast customers are now provided service through the Vanderbilt system.
(2)Represents average throughput from the acquisition date, June 30, 2003, through December 31, 2003. The Partnership has two operating segments, Midstream and Treating. The Partnership's Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while its Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. See Note 15 to the consolidated financial statements for financial information about these operating segments.
The Partnership's general partner interest is held by Crosstex Energy GP, L.P., a Delaware limited partnership. Crosstex Energy GP, LLC, a Delaware limited liability company, is Crosstex
Energy GP, L.P.'s general partner. Crosstex Energy GP, LLC manages the Partnership's operations and activities and employs the Partnership's officers.
References in this report to "Crosstex Energy, L.P.'s predecessor" or the "Partnership's predecessor" refer to Crosstex Energy Services, Ltd., a Texas limited partnership, substantially all of the assets of which were transferred to the Partnership at the closing of its initial public offering in December 2002.
As generally used in the energy industry and in this document, the following terms have the following meanings:
/d = per day
Btu = British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
Business Strategy
The Partnership's strategy is to increase distributable cash flow per unit by making accretive acquisitions of assets that are essential to the production, transportation, and marketing of natural gas; improving the profitability of its owned assets by increasing their utilization while controlling costs; accomplishing economies of scale through new construction or expansion in core operating areas; and maintaining financial flexibility to take advantage of opportunities. The Partnership's strategy is based on its expectation of a continued high level of drilling in its principal geographic areas and a process of ongoing divestitures of gas transportation and processing assets by large industry participants. The Partnership believes these two factors should present opportunities for continued expansion in its existing areas of operation as well as opportunities to acquire assets in new geographic areas that may serve as a platform for future growth. Key elements of the Partnership's strategy include the following:
•Pursuing accretive acquisitions. The Partnership intends to use its acquisition and integration experience to continue to make strategic acquisitions of midstream assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset. The Partnership pursues acquisitions that it believes will add to existing core areas in order to capitalize on its existing infrastructure, personnel, and producer and consumer relationships. The Partnership also examines opportunities to establish new core areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. The Partnership plans to establish new core areas primarily through the acquisition of key assets that will serve as a platform for further growth both through additional acquisitions and the construction of new assets. A recent example of establishing a new core area includes the Mississippi pipeline system acquired as part of the DEFS acquisition. This system provides the Partnership with a platform to develop a significant presence in the south central Mississippi area.
•Improving existing system profitability. After the Partnership acquires or constructs a new system, it begins an aggressive effort to market services directly to both producers and end users in order to connect new supplies of natural gas, improve margins, and fully utilize the system's capacity. Many of the Partnership's recently acquired systems have excess capacity that provides it opportunities to increase throughput with minimal incremental cost. As part of this process, the Partnership focuses on providing a full range of services to small and medium size independent producers and end users, including supply aggregation, transportation and hedging, which the Partnership believes provides it with a competitive
advantage when it competes for sources of natural gas supply. Additionally, the Partnership emphasizes increasing the percentage of our natural gas sales directly to end users, such as industrial and utility consumers in an effort to increase our operating margins. For the year ended December 31, 2003, approximately 58% of the Partnership's on-system natural gas sales were to industrial end users and utilities.
•Undertaking construction and expansion opportunities. The Partnership leverages its existing infrastructure and producer and customer relationships by constructing and expanding systems to meet new or increased demand for its gathering, transmission, treating, processing and marketing services. These projects include expansion of existing systems and construction of new facilities. The Partnership's 2002 acquisition of the Hallmark Lateral facilitated the establishment of connections between its Corpus Christi and its Gulf Coast systems which has increased its flexibility in balancing gas supply and market requirements throughout the regions covered. In August 2003, the Partnership expanded the capacity of its Gregory processing plant from 99,900 MMBtu/d to 166,500 MMBtu/d, a 67% increase over its previous capacity, and began marketing the additional gas through its Corpus Christi and Gulf Coast systems. The Partnership further enhanced the Gregory system by acquiring the Koch Ingleside Pipeline and connecting directly to a major end user customer.
Recent Acquisitions and Expansion
Duke Energy Field Services. In June 2003, the Partnership acquired various midstream assets located in Mississippi, Texas, Alabama and Louisiana from DEFS for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi that serves utility and industrial customers, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for several major oil companies in West Texas. The acquisition provided the Partnership with a new core area for growth in south central Mississippi, expanded its presence in West Texas, increased the total miles of its pipelines from 1,700 to 2,500 and enabled it to enter the business of carbon dioxide separation. In addition, the Partnership believes that the acquisition has increased the stability of its cash flow as operating profits from the Mississippi pipeline system are generated through purchasing, gathering, transporting and reselling natural gas which generates margins not affected by commodity prices, and a majority of the income it receives from the Seminole gas plant is based on fixed fees for carbon dioxide separation and sulfur removal.
Gregory Expansion. In August 2003, the Partnership completed an expansion of its Gregory processing plant. The expansion increased the plant capacity from approximately 99,900 MMBtu/d to 166,500 MMBtu/d, at a cost of approximately $7.0 million. In addition, the Partnership has significantly reduced its exposure to commodity prices by renegotiating a number of its commodity based contracts, where revenues were subject to fluctuating commodity prices, to fee-based contracts.
Subsequent Event. The Partnership entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power for $76.2 million. The acquisition will increase the Partnership's pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. The Partnership will finance the acquisition through borrowings under our existing bank credit facility, issuance of additional senior notes or other financing alternatives.
Other Developments
Partnership's Follow-on Offering. In September 2003, the Partnership completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. The Partnership received net proceeds of approximately $59.1 million, including an approximate $1.3 million capital contribution by the general partner. The net proceeds were used to repay borrowings outstanding under the bank credit facility of its operating partnership.
Bank Credit Facility. In June 2003, the Partnership's operating partnership, Crosstex Energy Services, L.P., entered into a new $100.0 million senior secured credit facility, which was increased to $120 million in October 2003, consisting of a $70.0 million acquisition facility and a $50.0 million working capital and letter of credit facility. As of December 31, 2003, the operating partnership had $20.0 million of outstanding borrowings under the acquisition facility and $30.3 million of letters of credit issued under the working capital and letter of credit facility. The credit facility matures in June 2006.
Secured Secured Notes. In June 2003, the operating partnership entered into a master shelf agreement with an institutional lender pursuant to which it issued $30.0 million of senior secured notes with an interest rate of 6.95% and a maturity of seven years. In July 2003, the operating partnership issued $10.0 million of senior secured notes pursuant to the master shelf agreement with an interest rate of 6.88% and a maturity of seven years. The senior secured notes are guaranteed by the operating partnership's subsidiaries and us. The operating partnership used the net proceeds from the senior notes offering to repay indebtedness under its bank credit facility.
Midstream Division
Gathering and Transmission. The Partnership's primary Midstream assets include systems located primarily along the Texas Gulf Coast and in south-central Mississippi, which, in the aggregate, consist of approximately 2,500 miles of pipeline and three processing plants and contributed approximately 78% and 72% of our gross profit in 2003 and 2002, respectively.
•Gulf Coast System. The Gulf Coast system is an intrastate pipeline system consisting of approximately 484 miles of gathering and transmission pipelines with a mainline from Refugio County in south Texas running northeast along the Gulf Coast to the Brazos River in Fort Bend County near Houston. The system's gathering and transmission pipelines range in diameter from 4 to 20 inches. The Partnership acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million.
The Gulf Coast system has two supply pipeline laterals which connect to gathering systems which collect natural gas from approximately 80 receipt points and five treating and processing plants operated by third parties. This system has three delivery laterals which deliver natural gas directly to large industrial and utility consumers along the Gulf Coast. The system interconnects with multiple third party pipelines through which the Partnership may purchase volumes not gathered through its systems for resale or through which it might deliver natural gas to customers which are not connected to its system. The Partnership transports gas on the TXU Lone Star pipeline providing access for its Gulf Coast mainline system in Fort Bend County to the Katy hub, a major natural gas physical exchange that allows access to seven third party pipelines, including Kinder Morgan, TECO and Trunkline. The Gulf Coast system has a capacity of 210,600 MMBtu/d and average throughput on this system was approximately 85,000 MMBtu/d for the year ended December 31, 2003.
The Partnership generates operating profits in its Gulf Coast system through the margins it earns by purchasing, gathering, transporting and reselling natural gas. The Partnership
purchases natural gas from a producer, pipeline or marketing company and then transport and resells the gas. As of December 31, 2003, the Partnership was purchasing gas from over 70 producers primarily pursuant to month-to-month contracts and was reselling the natural gas to approximately 10 customers primarily pursuant to short-term or month-to-month arrangements. For the year ended December 31, 2003, approximately 92% of the natural gas volumes it purchased was purchased at a fixed price relative to an index and the remainder was purchased at a percentage of an index, and all the natural gas volumes it sold was sold at a fixed price relative to an index.
•Vanderbilt System. The Partnership's Vanderbilt system consists of approximately 200 miles of gathering and transmission pipelines located in Wharton and Fort Bend Counties near its Gulf Coast system. Natural gas is supplied to the system from over 27 receipt points. The gas had been sold to the Exxon Katy plant and, in June 2003, the Partnership reversed the flow of gas and began deliveries to the Formosa Hydrocarbons processing plant at Point Comfort, Texas. The Partnership's Vanderbilt system has a capacity of 141,700 MMBtu/d and average throughput was approximately 49,000 MMBtu/d for the year ended December 31, 2003. The Partnership acquired the Vanderbilt system in December 2002 for a purchase price of $12.0 million.
All the gas in the Vanderbilt system is now sold to Formosa Hydrocarbons under a ten year agreement which began in June 2003 to supply up to 60,000 MMBtu/d. The gas is sold to Formosa at a fixed price relative to an index. Gas is purchased from approximately 15 producers, primarily pursuant to month-to-month arrangements, at over 25 receipt points. Approximately 55% percent of the gas is purchased at a percentage of an index, and the remainder is purchased at a fixed price relative to an index. The Partnership generates operating profits in the system through the margins it earns by purchasing gas from producers, then gathering, transporting and reselling the natural gas to Formosa.
•Corpus Christi System. The Corpus Christi system is an intrastate pipeline system consisting of approximately 295 miles of gathering and transmission pipelines and extending from supply points in south Texas to markets in the Corpus Christi area. The Partnership's gathering and transmission pipelines range in diameter from four to 20 inches. The Partnership acquired the Corpus Christi system in May 2001 in conjunction with the acquisition of the Gregory gathering system and Gregory processing plant, which it collectively refers to as the CCNG Acquisition, for an aggregate purchase price of approximately $30 million. The Partnership's Corpus Christi system had average throughput of approximately 152,000 MMBtu of gas per day at the time of its acquisition. The main lines comprising the Corpus Christi system were constructed at various times from the 1940's through the 1990's.
Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 16 treating and processing plants and third party gathering systems and pipelines. The system interconnects with multiple third party pipelines through which the Partnership purchases volumes not gathered through its systems for resale and delivers natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system has a capacity of 355,950 MMBtu/d and average throughput on this system was approximately 213,800 MMBtu/d for the year ended December 31, 2003.
In June 2002, the Partnership acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows it to access new markets within Texas and to interconnect to the Florida Gas system within Texas. The Partnership has constructed an addition to this transmission line creating a connection between its Gulf Coast system and its Corpus Christi system. This connection allows the Partnership to transport gas between our
two systems, thereby reducing our dependence on third-party suppliers, move gas supplies to more favorable markets and enhance our margins. In November 2002, the Partnership completed construction of the interconnect between the Hallmark Lateral and the Florida Gas system. With this connection, the Partnership began selling gas into the Florida markets and sold approximately 57,000 MMBtu/d for the year ended December 31, 2003.
The Partnership generates operating profits in its Corpus Christi system through the margins it earns by purchasing, gathering, transporting and reselling natural gas. As of December 31, 2003, the Partnership was purchasing natural gas from approximately 35 producers generally on month-to-month or short-term arrangements. For the year ended December 31, 2003, substantially all of the natural gas volumes the Partnership purchased were purchased at a fixed price relative to an index. The Corpus Christi system transports natural gas to the Corpus Christi area where the Partnership's customers include multiple major refineries and other industrial installations, as well as the local electric utility. As of December 31, 2003, the Partnership was selling gas to over 20 customers primarily pursuant to contracts that expire at various times between 2003 and 2006. For the year ended December 31, 2003, all of the natural gas volumes the Partnership sold were sold at a fixed price relative to an index.
•Gregory Gathering System. The Partnership acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the acquisition of the Corpus Christi system. The plant and the gathering system are located north of Corpus Christi, Texas. The gathering system is connected to approximately 70 receipt points in San Patricio County, the Corpus Christi Bay area, Mustang Island, and adjacent coastal areas. The gathering system consists of approximately 297 miles of pipeline ranging in diameter from two inches to 18 inches with a total estimated throughput capacity of 222,000 MMBtu/d. The gathering system had average throughput of approximately 151,000 MMBtu/d for the year ended December 31, 2003 compared to an average throughput of approximately 76,500 MMBtu/d of gas per day at the time of its acquisition. The Gregory Gathering System was constructed in the 1980s.
The Partnership generates operating profits in its Gregory gathering system through the margins earned by purchasing, gathering, transporting and reselling natural gas. As of December 31, 2003, the Partnership was purchasing gas from over 60 producers primarily pursuant to month-to-month contracts, and for the year ended December 31, 2003, approximately 95% of the natural gas volumes it purchased were purchased at a fixed price relative to an index and the remainder was purchased at percentage of an index.
•Gregory Processing Plant. The Partnership's Gregory processing plant is a cryogenic turbo expander with a 210,000 gallon per day fractionator that removes liquid hydrocarbons from the liquids-rich gas produced into the Gregory gathering system. The Partnership's Gregory processing plant inlet capacity was expanded from 99,900 MMBtu/d to approximately 166,500 MMBtu/d during 2003, and average throughput was approximately 106,000 MMBtu/d for the year ended December 31, 2003. At the time of acquisition, the plant was processing approximately 43,400 MMBtu/d of gas per day. The Gregory processing plant was constructed in the 1980s and expanded and upgraded in 1998 and 2003.
In addition to the margins generated by the Gregory gathering system, the Partnership generates revenues at its Gregory processing plant under two types of arrangements:
•For the year ended December 31, 2003, the Partnership purchased approximately 16% of the natural gas volumes on its Gregory system under contracts in which it was exposed to the risk of loss or gain in processing the natural gas. Under these contracts, the
Partnership fractionates the NGLs into separate NGL products, which it then sells at prices based upon the market price for NGL products. The processed natural gas is delivered to multiple customers at prices based on a fixed price relative to a monthly index. Since the Partnership extracts Btus from the gas stream in the form of the liquids or consumes it as fuel during processing, the Partnership reduces the Btu content of the natural gas but seek to more than offset this by creating value from the separated NGL products. Accordingly, the Partnership's margins under these arrangements can be negatively affected in periods where the value of natural gas is high relative to the value of NGLs.
•For the year ended December 31, 2003, the Partnership purchased approximately 84% of the natural gas volumes on its Gregory system at a spot or market price less a discount that includes a conditioning fee for processing and marketing the natural gas and NGLs at its Gregory processing plant with no risk of loss or gain in processing the natural gas. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas.
•Arkoma Gathering System. The Partnership acquired the Arkoma gathering system, located in the Southeastern region of Oklahoma, in September 2000 for $10.5 million. In addition, since acquiring this system, the Partnership has acquired the Shawnee extension, consisting of 15 miles of gathering pipelines extending through additional supply areas in this region. The Arkoma gathering system when acquired was approximately 84 miles in length and included a 3,700 horsepower compressor station. With the addition of the Shawnee extension and additional well connections, the system is now approximately 100 miles in length and ranges in diameter from 2 to 10 inches. This low-pressure system gathers gas from approximately 170 wells to three compressor stations for discharge to a mainline transmission pipeline. This system has a capacity of 21,400 MMBtu/d and average throughput was approximately 13,000 MMBtu/d for the year ended December 31, 2003.
The Partnership generates a margin for gathering and transporting gas in the Arkoma gathering system equal to a percentage of the proceeds from the sale of the natural gas to the mainline transmission pipeline into which it delivers. The Partnership takes title to the gas at the point of receipt into the gathering system, with payment based upon an allocation of the metered volume sold into the mainline transmission facilities of our customer with the producer sharing their pro rata portion of the fuel costs for the compression and the removal of water from the natural gas stream.
•Mississippi Pipeline System. The Partnership acquired the Mississippi pipeline system from DEFS in June 2003 in connection with the DEFS acquisition. The Mississippi pipeline system is located in 15 counties of south Mississippi spanning from the city of Jackson in the northwest to Hattiesburg in the southeast. The system has wellhead supply connections in most of the gas fields in the counties of operation-primarily Jasper, Jefferson Davis, Lawrence, Marion and Simpson counties. The system delivers natural gas through direct market connections to utilities and industrial end users. The pipeline system consists of approximately 638 miles of pipeline ranging in diameter from four to 20 inches with a total estimated capacity of 198,500 MMBtu/d. Average throughput on this system was approximately 79,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970s.
The Partnership generates operating profits in our Mississippi pipeline system by purchasing, gathering, transporting and reselling natural gas. The Partnership purchases gas from
approximately 50 producers at the delivery points into the system and gas is sold to approximately 15 customers. The majority of contracts provide that natural gas volumes are purchased at a fixed price relative to an index.
•Seminole Gas Processing Plant. The Partnership owns an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas. The Seminole plant has dedicated long-term reserves from the Seminole San Andres unit, to which it also supplies carbon dioxide under a long-term arrangement. Revenues at the plant are derived from a fee it charges producers, including those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.59 for each Mcf of carbon dioxide returned. The plant also receives 50% of the NGLs produced by the plant. The Partnership has entered into a one-year contract with Duke Energy NGL Services, L.P. to market its NGLs on its behalf. The Partnership receives its share of proceeds from the sale of carbon dioxide from the plant operator. The Partnership is separately billed by the plant operator for its share of expenses. The plant had capacity of 150,000 Mcf/d at the time of acquisition. The recently completed expansion increased capacity by 60,000 Mcf/d, increasing total capacity to 210,000 Mcf/d. Average throughput for the plant was approximately 144,000 Mcf/d for the last six months of 2003. The plant was constructed in the 1980s.
•Conroe Gas Plant And Gathering System. The Partnership acquired the Conroe gas plant and gathering system in June 2003 in connection with the DEFS asset acquisition. Located in Montgomery County, Texas, the Conroe gas plant is a cryogenic gas processing plant with 10 miles of gathering pipelines located within the Conroe Field Unit, which is operated by ExxonMobil. The plant gathers low pressure and high pressure natural gas through contracts with over 20 producers. The plant has outlet natural gas connections to Kinder Morgan Texas Pipeline, L.P. and Copano Field Services. Recovered NGLs are delivered into the Chaparral NGL pipeline. The plant has a capacity of 70,265 MMBtu/d and average throughput on this system was approximately 26,000 MMBtu/d for the year ended December 31, 2003. The Conroe gas plant was constructed in the 1930s.
The Partnership generates operating profits at our Conroe gas plant from one customer primarily from compression and processing fees and from retaining 40% of the NGLs from the recycled lift gas.
•Alabama Pipeline System. The Partnership acquired the Alabama pipeline system in June 2003 in connection with the DEFS asset acquisition. The system is located in Fayette, Lamar, Picken and Tuscaloosa Counties in west-central Alabama. The system gathers coalbed methane gas from the Black Warrior Basin and other conventional wells. The system is a series of three natural gas gathering and transmission systems consisting of approximately 125 miles of four to twelve inch pipeline with an estimated capacity of 72,300 MMBtu/d. One supplier to the system accounted for over half of the gas gathered. The gas is delivered primarily to industrial end users. Average throughput on this system was approximately 14,000 MMBtu/d for the year ended December 31, 2003. The system was constructed in the 1970's.
The Partnership generates operating profits in its Alabama pipeline system by gathering, transporting and reselling natural gas. All gas is purchased at the delivery points into the system. The majority of the contracts are priced at a fixed basis to an area index and the Partnership sells gas to approximately five customers.
•Other Systems. The Partnership owns several small gathering systems totaling approximately 135 miles, including the Manziel system in Wood County, Texas, the San Augustine system in
San Augustine County, Texas, the Freestone Rusk system in Freestone County, Texas, the Jack Starr and North Edna systems in Jackson County, Texas and the Cadeville and Aurora Centana systems in Louisiana. Through Crosstex Pipeline Partners, a limited partnership of which the Partnership is the co-general partner, the Partnership owns a 28% interest in five gathering systems in east Texas, totaling 64 miles with a combined capacity of 119,000 MMBtu/d. The Partnership also owns five industrial bypass systems each of which supplies natural gas directly from a pipeline to a dedicated customer. The combined volumes for these five industrial bypass systems was approximately 4,200 MMBtu/d for the year ended December 31, 2003. In addition to these systems, the Partnership owns various smaller gathering and transmission systems located in Texas, New Mexico and Louisiana.
Producer Services. The Partnerhip currently purchases for resale volumes of natural gas that do not move through its gathering, processing or transmission assets from over 50 independent producers. The Partnership engages in such activities on more than 20 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. The Partnership focuses on supply aggregation transactions in which it either purchases and resells gas and thereby eliminates the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer. Profits from energy trading activities for the year ended December 31, 2003 and 2002 were $1.9 million and $2.7 million, respectively.
The Partnership's business strategy includes developing relationships with natural gas producers to facilitate the purchase of its production on a long-term basis. The Partnership believes that this business also provides it with strategic insights and valuable market intelligence which may impact its expansion and acquisition strategy.
The Partnership offers to its customers the ability to hedge their purchase or sale price by agreeing to sell to it or to purchase from it volumes of natural gas. This risk management tool enables its customers to reduce pricing volatility associated with the sale and purchase of natural gas. When the Partnership agrees to purchase or sell natural gas from a customer, it contemporaneously executes a contract for the sale or purchase of such natural gas or the Partnerhip enters into an offsetting obligation using futures contracts on the New York Mercantile Exchange or by using over-the-counter derivative instruments with third parties.
Treating Division
The Partnership operates treating plants which remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications. The Partnership's treating division contributed approximately 22% and 27% of our gross margin in 2003 and 2002, respectively. The Partnership's treating business has grown from 35 plants in operation at December 31, 2002 to 52 plants in operation at December 31, 2003.
As of December 31, 2003, the Partnership owned 61 treating plants, 41 of which were operated by its personnel, 11 of which were operated by producers, and 9 of which were held in inventory. The Partnership entered the treating business in 1998 with the acquisition of WRA Gas Services and it is now one of the largest gas treating operations in the Texas Gulf Coast. The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced to transportation systems to ensure that it meets pipeline quality specifications. Natural gas from certain formations in the Texas Gulf Coast, as well as other locations, is high in carbon dioxide. The majority of the Partnership's active plants are treating gas from the Wilcox and Edwards formations in the Texas Gulf Coast, both of which are deeper formations that are high in carbon dioxide. The
Partnership's active treating facilities include 47 amine plants and five hydrogen sulfide scavenger installations. In cases where producers pay the Partnership to operate the treating facilities, the Partnership either charges a fixed rate per Mcf of natural gas treated or charges a fixed monthly fee.
In addition to the Partnership's treating plants, it has three gathering systems with an aggregate of 43 miles of gathering pipeline located in Val Verde, Crockett, Dewitt and Live Oak counties, Texas that are connected to approximately 73 producing wells. These gathering systems are connected to three of the Partnership's treating plants. The diameter of these gathering pipelines ranges from two to six inches. These gathering assets in the aggregate have a capacity of 61,000 MMBtu/d and average throughput was approximately 20,800 MMBtu/d for the year ended December 31, 2003. In cases where the Partnership both gathers and treats natural gas, its fee is generally based on throughput.
A component of the Partnership's strategy is to purchase used plants and then refurbish and repair them at its shop and seven-acre yard in Victoria, Texas and its 14-acre yard in Odessa, Texas. The Partnership believes that it can purchase used plants and recondition them at a significant cost savings to purchasing new plants. The Partnership has an inventory of plants of varying sizes which can be deployed after refurbishment. The Partnership also mounts most of the plant equipment on skids allowing them to be moved in a timely and cost efficient manner. At such time as the Partnership's active plants come offline, the Partnership will put them in its inventory pending redeployment. The Partnership believes its plant inventory gives it an advantage of several weeks in the time required to respond to a producer's request for treating services.
Treating process. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb the impurities from the gas. After mixing, gas and amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute. The size range of the 52 plants in operation is 3.5 to 300 gallons per minute, and the size range of the 9 plants in inventory is 3.5 to 1,000 gallons per minute.
Hydrogen sulfide scavenger facilities use a liquid or solid chemical that reacts with hydrogen sulfide thereby removing it from the gas. Used chemicals are disposed of and cannot be regenerated as amine can. The facilities are primarily vertical towers mounted on concrete foundations. As of December 31, 2003, the Partnership had two such facilities which were operated by the producer.
Industry Overview
The following diagram illustrates the natural gas treating, gathering, processing, fractionation and transmission process.
The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.
Natural gas treating. Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide. Treating plants are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems to ensure that it meets pipeline quality specifications.
Natural gas processing and fractionation. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream, as well as the removal of contaminants. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.
Natural gas transmission. Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, plant tailgates, and gathering systems and deliver it to industrial end-users, utilities and to other pipelines. All of our transmission pipelines are intrastate systems.
Risk Management
As the Partnership purchases natural gas, it establishes a margin by selling natural gas for physical delivery to third party users, using over-the-counter derivative instruments or by entering into a future delivery obligation under futures contracts on the New York Mercantile Exchange. Through these transactions, the Partnership seeks to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. The Partnership's policy is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes.
Competition
The business of providing natural gas gathering, transmission, treating, processing and marketing services is highly competitive. The Partnership faces strong competition in acquiring new natural gas supplies. The Partnership's competitors in obtaining additional gas supplies and in treating new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. The main difference between the Partnership and its competitors is that the Partnership offers most midstream services, while its competitors typically offer only a few select services. Many of its competitors have substantially greater capital resources and control substantially greater supplies of natural gas. The Partnership's major competitors in the Texas Gulf Coast area for natural gas supplies and markets include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services. The Partnership's major competitors in Mississippi for natural gas supplies and markets include Southern Natural Gas and Gulf South Pipeline Company.
The Partnership's gas treating operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant and operations similar to ours. The Partnership also faces competition from vendors of used equipment that occasionally operate plants for producers. The Partnership's primary competitor for natural gas treating services in our principal market area is The Hanover Company.
In marketing natural gas, the Partnership has numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with its marketing operations.
Natural Gas Supply
The Partnership's end-user pipelines have connections with major interstate and intrastate pipelines, which the Partnership believes have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of the Partnership's gathering systems, it evaluated well and reservoir data furnished by producers to determine the availability of natural gas supply for the systems. Based on those evaluations, the Partnership believes that there should be adequate natural gas supply to recoup its investment with an adequate rate of return. The Partnership does not routinely obtain independent evaluations of reserves
dedicated to its systems due to the cost of such evaluations. Accordingly, the Partnership does not have estimates of total reserves dedicated to its systems or the anticipated life of such producing reserves.
Credit Risk and Significant Customers
The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the Partnership's purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to the Partnership's overall profitability.
During the year ended December 31, 2003, the Partnership had one customer that individually accounted for more than 10% of consolidated revenues. During the year ended December 31, 2003, Kinder Morgan Tejas accounted for 20.5% of our consolidated revenue. While this customer represents a significant percentage of consolidated revenues, the loss of this customer would not have a material impact on our results of operations.
Regulation
Regulation by FERC of Interstate Natural Gas Pipelines. Under the Natural Gas Act ("NGA"), the Federal Energy Regulatory Commission ("FERC") generally regulates the transportation of natural gas in interstate commerce. The Partnership does not own any interstate natural gas pipelines, so FERC does not directly regulate any of its facilities or operations. However, as discussed below, the Partnership does perform some interstate transmission service that is incidental to its intrastate business, and this interstate transmission is subject to FERC rate regulation. Also, FERC's regulation of interstate transportation by others indirectly influences certain aspects of the Partnership's business and the market for its products. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines' rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Intrastate Pipeline Regulation. The Partnership's intrastate natural gas pipeline operations are not subject to regulation by FERC, but they are subject to regulation by various agencies of the states in which they are located, principally the Texas Railroad Commission, or TRRC. However, to the extent that the Partnership's intrastate pipeline systems provide incidental transportation of natural gas in interstate commerce, the rates, terms and conditions of such transportation services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act ("NGPA"). Section 311 applies to, among other things, the providing of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.
The Partnership's operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates the Partnership charges for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. The Partnership cannot predict whether such a complaint will be filed against it or whether the TRRC will change its regulation of these rates.
A twelve-mile section of the Partnership's Mississippi gathering system is regulated by the Mississippi Oil and Gas Board as it transports gas not owned by the Partnership for a fee. The Partnership's one hundred twenty-five mile gathering system in Oklahoma is not regulated by the Oklahoma Corporation Commission. Similarly, gathering systems the Partnership owns in Alabama and Louisiana are not subject to regulation by the Alabama State Oil and Gas Board and the Louisiana Office of Conservation respectively. While it is possible that Alabama, Louisiana, Oklahoma, Mississippi and New Mexico may try to assert or expand jurisdiction on those lines, it is not likely that the assertion or expansion of that jurisdiction would have a significant effect on the Partnership's operations in those states because all tend to apply Federal regulations to natural gas pipeline facilities without numerous additional state-specific requirements.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. The Partnership owns a number of natural gas pipelines that it believes meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of the Partnership's gathering facilities, for purposes of rate regulation to the extent it provides NGPA Section 311 services over such facilities, are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
The Partnership is subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom the Partnership contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. The Partnership's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. The Partnership's gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Partnership cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which the Partnership sells natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The Partnership's sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules
and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect less extensive regulation. The Partnership cannot predict the ultimate impact of these regulatory changes on its natural gas marketing operations, and we note that some of FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. The Partnership does not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.
Environmental Matters
General. The Partnership's operation and the Partnership's possible future operation of processing and fractionation plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionation and storage of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to release of hazardous substances or wastes into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases the Partnership's overall costs of doing business, including cost of planning, constructing, and operating plants, pipelines, and other facilities. Included in the Partnership's construction and operation costs are capital cost items necessary to maintain or upgrade equipment and facilities. The Partnership will likely incur similar costs upon its acquisition of assets if it acquires operating assets.
Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays. While the Partnership believes that it currently holds material governmental approvals required to operate its major facilities, the Partnership is currently evaluating and updating permits for certain of its facilities that primarily were obtained in recent acquisitions. As part of the regular overall evaluation of its operations, the Partnership has implemented procedures to and are presently working to ensure that all governmental approvals, for both recently acquired facilities and existing operations, are updated as may be necessary. The Partnership believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on its operating results or financial condition.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with the Partnership's possible future operations, and the Partnership cannot assure you that it will not incur significant costs and liabilities including those relating to claims for damage to property and persons as a result of such upsets, releases, or spills. In the event of future increases in costs, the Partnership may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject the Partnership to substantial expense, including both the cost to comply with applicable laws and regulations and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to property. The
Partnership will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and in order to minimize the costs of such compliance.
Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting the Partnership's possible future operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although "petroleum" as well as natural gas and NGLs are excluded from CERCLA's definition of a "hazardous substance," in the course of future, ordinary operations, we may generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous state laws.
The Partnership also generates, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the Environmental Protection Agency, or EPA, has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.
The Partnership currently owns or leases, and has in the past owned or leased, and in the future the Partnership may own or lease, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of on or under various properties owned or leased by the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which
such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination.
The Partnership recently acquired two assets from DEFS that have environmental contamination, including a gas plant in Montgomery County, near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the Partnership's purchase agreement, Duke has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, the remediation costs associated with the Conroe site will be covered by agreements with TRC Companies and AIG. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.
Air Emissions. The Partnership's operations are, and the Partnership's possible future operations will likely be, subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, the Partnership's processing and fractionating plants, pipelines, and storage facilities or any of its future assets that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. Such requirements, if applicable to our operations, could cause the Partnership to incur capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission related issues. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of the Partnership's facilities and which may apply to some of its possible future facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although the Partnership can give no assurances, the Partnership believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on its financial condition or operating results.
Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that the Partnership is in substantial compliance with Clean Water Act permitting requirements as well as the
conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on its results of operations.
Employee Safety. The Partnership is subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that the Partnership's operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. Presently, the Partnership operates in only one area that is designated as a critical habitat for a certain species of beetle. This area consists of 29 counties in eastern and central Oklahoma into which part of the Partnership's gathering system extends. A coalition of oil and gas industry and regulatory agencies are currently working together to minimize impacts on future construction and operation activities for oil and gas production and transportation. This designated area has had no material effect on the Partnership's operations in Oklahoma to date. While the Partnership has no reason to believe that the Partnership operates in any other area that is currently designed as habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause the Partnership to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Safety Regulations. The Partnership's pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, and the Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004 relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines and segments of gathering lines in certain populated areas 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. The Partnership believes that its pipeline operations are in substantial compliance with applicable HLPSA and PIM requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA or PIM requirements will not have a material adverse effect on the Partnership's results of operations or financial positions.
Office Facilities
In addition to the Partnership's gathering and treating facilities discussed above, we, together with the Partnership, occupy approximately 21,000 square feet, increasing up to approximately 40,000 square feet over the next two years, of space at our executive offices in Dallas, Texas under a lease expiring in March 2010.
Employees
As of December 31, 2003, the Partnership's operating Partnership, had approximately 189 full-time employees. Approximately half of the Partnership's employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. Neither we nor the Partnership is party to any collective bargaining agreements, and neither we nor the Partnership had any significant labor disputes in the past. We believe that we have good relations with our employees.
Item 2.
Item 2. Properties
A description of our 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. The Partnership 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 Gregory processing plant is on land that it owns in fee.
The Partnership believes that it has satisfactory title to all of its assets. Title to property may be subject to encumbrances. The Partnership believes that none of such encumbrances should materially detract from the value of its properties or from our interest in these properties or should materially interfere with their use in the operation of its business.
Item 3.
Item 3. Legal Proceedings
We are not currently a party to any material litigation. The Partnership operations are subject to a variety of risks and disputes normally incident to its business. As a result, at any given time the Partnership may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies with insurers in amounts and with coverage and deductibles as its managing general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect the Partnership 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, 2003.
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 13, 2004, at an initial public offering price of $19.50 per share. On March 12, 2004, there were approximately 2,522 record holders and beneficial owners (held in street name) of our common stock.
We have not paid any cash dividend as of the date of this report, however, we intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:
•federal income taxes, which we are required to pay because we are taxed as a corporation;
•the expenses of being a public company;
•other general and administrative expenses;
•capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner's 2.0% general partner interest; and
•reserves our board of directors believes prudent to maintain, including reserves equal to the benefit we will receive in 2004 from our existing net operating loss carryforwards.
If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions.
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.
Recent Sales of Unregistered Securities
In January 2003, we issued: (i) 239,745 shares of our Series A 71/2% Cumulative Convertible Preferred Stock to Yorktown Energy Partners IV, L.P., Barry E. Davis, A. Chris Aulds, James R. Wales, Lisa M. Brecht, John W. Daugherty, William W. Davis, Mark E. Huff, Mike W. Hopkins, Jack M. Lafield, Rodney A. Madden and Michael P. Scott as a dividend paid pursuant to the terms of the Series A 71/2% Cumulative Convertible Preferred Stock; and (ii) 22,236 shares of our Series B 71/2% Cumulative Convertible Preferred Stock to Yorktown Energy Partners IV, L.P., Lubar Nominees, Barry E. Davis, A. Chris Aulds and James R. Wales as a dividend paid pursuant to the terms of the Series B 71/2% Cumulative Convertible Preferred Stock.
In August 2003, we sold in a private placement: (i) 10,000 of our Series B 71/2% Cumulative Convertible Preferred Stock to Marc Lyons and Stewart McCorkle, each of whom is an employee of a subsidiary of the registrant, for an aggregate purchase price of $120,000, consisting of $12,000 in cash and $108,000 in the form of full recourse promissory notes secured by the shares purchased by
such individuals; and (ii) 20,000 shares of our Series C 71/2% Cumulative Convertible Preferred Stock to Dale Wilson, an employee of a subsidiary of the registrant, for an aggregate purchase price of $280,000, consisting of $28,000 in cash and $252,000 in the form of a full recourse promissory note secured by the shares purchased by such individual.
Upon the completion of our initial public offering in January 2004, all of the above shares of preferred stock were converted into common stock. The sales and issuances of securities in all of the above transactions were deemed to be exempt from registration under the Securities Act of 1933, in reliance upon Section 4(2) thereof, or Regulation D or Rule 701 promulgated thereunder, as transactions by an issuer not involving a public offering. Recipients of the securities in each such transaction represented their intentions to acquire such securities for investment purposes only and not with a view to or for sale in connection with any distribution thereof and appropriate legends were affixed to the instruments issued in such transactions. All recipients either received adequate information about the registrant or had access, through employment relationships or otherwise, to such information. In addition, the foregoing transactions were consummated without the use of underwriters.
Use of Proceeds from Registered Securities
On January 12, 2004, our registration statement on Form S-1 (Registration No. 333-110095) was declared effective by the Securities and Exchange Commission in connection with the public offering of 2,306,000 shares of common stock (plus up to 345,900 additional shares of common stock upon the exercise of the underwriters' over-allotment option), which commenced on January 13, 2004. The initial public offering did not terminate prior to the sale of all the securities registered. The underwriters of the offering were A.G. Edwards & Sons, Inc., Raymond James & Associates, Inc., and RBC Dain Rauscher Inc. The initial public offering consisted solely of one class of common stock. The number of securities registered, including the shares of common stock subject to the underwriters' over-allotment option, was 2,651,900, all of which have been sold to the public.
The price to public, underwriting discounts and commissions, and proceeds to the Partnership are set forth in the following table:
(1)Before deducting expenses of approximately $1.5 million paid by us.
The net proceeds that we received from the initial public offering of the shares of common stock, after deducting expenses of approximately $1.5 million and underwriting discounts and commissions, was approximately $4.8 million. We plan to use the net proceeds received by us from the initial public offering for general corporate expenses, but have not done so as of the date of this report. We did not receive any of the net proceeds from any sale of shares of common stock by any selling stockholder. The selling stockholders used approximately $5.0 million of the net proceeds received by them to retire outstanding notes from the selling stockholders held by us.
Item 6.
Item 6. Selected Financial Data
The following table sets forth selected historical financial and operating data of Crosstex Energy, Inc. and our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated. The selected historical financial data are derived from the audited financial statements of Crosstex Energy, Inc. or our predecessor, Crosstex Energy Services, Ltd. The investment in our predecessor by Yorktown Energy Partners IV, L.P. in May 2000 resulted in the dissolution of the predecessor partnership and the creation of a new partnership with the same organization, purpose, assets and liabilities. Accordingly, the financial statements of our predecessor for 2000 are divided into the four months ended April 30, 2000 and the eight months ended December 31, 2000 because a new basis of accounting was established effective May 1, 2000 to give effect to the Yorktown transaction. In addition, our summary historical financial and operating data includes the results of operations of the Arkoma system beginning in September 2000, the Gulf Coast system beginning in September 2000, the CCNG system, which includes the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, beginning in May 2001, the Vanderbilt system beginning in December 2002 and the DEFS assets beginning in June 2003.
The table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
(1)We, through our ownership interest in the Partnership, are the successor to Crosstex Energy Services, Ltd. Results of operations and balance sheet data prior to May 1, 2000 represent historical results of the predecessor to Crosstex Energy Services, Ltd. These results are not necessarily comparable to the results of Crosstex Energy Services, Ltd. subsequent to May 2000 due to the new basis of accounting. There are no income tax provisions for these predecessor periods because Crosstex Energy Services, Ltd. was a limited partnership not subject to federal income taxes.
(2)We recognized gains of $11.1 million in 2002 and $18.4 million in 2003 as a result of the Partnership issuing additional units to the public in public offerings at prices per unit greater than our equivalent carrying value.
(3)Per share amounts have been adjusted for the two-for-one stock split made in conjunction with an initial public offering in January 2004.
(4)Gross margin is defined as revenue less related cost of purchased gas.
(5)Represent volumes for treating plants operated by the Partnership whereby it receives a fee based on the volumes treated.
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. 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. These partnership interests consist of (i) 333,000 common units and 4,667,000 subordinated units, representing a 54.3% limited partner interest 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.
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 partner's 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 operations. 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. The Partnership's Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while its Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the year ended December 31, 2003, 78% of the Partnership's gross margin was generated in the Midstream division, with the balance in the Treating division, and approximately 71% of its gross margin was generated in the Texas Gulf Coast region. The Partnership focuses on gross margin to manage its business because its business is generally to gather, process, transport, market or treat gas for a fee or a buy-sell margin. The Partnership buys and sells most of its gas at a fixed relationship to the relevant index price so its margins are not significantly affected by changes in gas prices. As explained under "Commodity Price Risk" below, the Partnership enters into financial instruments to reduce volatility in its gross margin due to price fluctuations.
Since the Partnership's formation, it has grown significantly as a result of its construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2000 through December 31, 2003, the Partnership had invested approximately $222.0 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 the Partnership's 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 results of operations are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities or treated at its treating plants as well as fees earned from recovering carbon dioxide and natural gas liquids at a non-operated processing plant. The Partnership generates revenues from four primary sources:
•gathering and transporting natural gas on the pipeline systems it owns;
•processing natural gas at its processing plants;
•treating natural gas to remove carbon dioxide and other impurities at its treating plants; and
•providing producer services.
The bulk of the Partnership's operating profits are derived from the margins it realizes for gathering and transporting 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 the Partnership manages its business to reduce the impact of price volatility.
The Partnership generates producer services revenues through the purchase and resale of natural gas. The Partnership currently purchases for resale volumes of natural gas that do not move through its gathering, processing or transmission assets from over 50 independent producers. The Partnership engages in such activities on more than 20 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. The Partnership focuses on supply aggregation transactions in which it either purchases and resells gas and thereby eliminates the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or acts as agent for the producer.
The Partnership generates treating revenues under three arrangements:
•a volumetric fee based on the amount of gas treated, which accounted for approximately 55% and 66% of the operating income in its Treating division for the years ended December 31, 2003 and 2002, respectively;
•a fixed fee for operating the plant for a certain period, which accounted for approximately 38% and 22% of the operating income in its Treating division for the years ended December 31, 2003 and 2002, respectively; or
•a fee arrangement in which the producer operates the plant, which accounted for approximately 7% and 12% of the operating income in its Treating division for the years ended December 31, 2003 and 2002, respectively.
Typically, the Partnership incurs minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through its pipeline assets. Therefore, the Partnership recognizes a substantial portion of incremental gathering and transportation revenues as operating income.
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore, do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.
We modified certain terms of certain outstanding options 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 elect to cash out the options or the election to cash out the options lapses. 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 remaining modified options will be accounted for as fixed options. We recognized total compensation expense of approximately $5.0 million related to these modified options in the year ended December 31, 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 are the acquisitions of the Partnership's CCNG system, Vanderbilt system and DEFS assets.
The Partnership acquired the CCNG system in May 2001 for a purchase price of approximately $30.0 million. The CCNG system included four principal assets: the Corpus Christi system, the Gregory gathering system, the Gregory processing plant and the Rosita treating plant.
•The Corpus Christi system consists of approximately 295 miles of gathering and transmission lines extending from supply points in south Texas to markets in Corpus Christi Texas, with average throughput of approximately 152,000 MMBtu of gas per day at the time of the acquisition.
•The Gregory gathering system consists of approximately 297 miles of gathering lines located primarily in the Corpus Christi Bay area, with average throughput of approximately 76,500 MMBtu of gas per day at the time of the acquisition.
•The Gregory processing plant processes most of the gas gathered by the Gregory gathering system, extracting the liquids, fractionating them into NGLs, and selling the remaining residue gas. At the time of the acquisition, the plant was processing approximately 43,400 MMBtu of gas per day.
•The Rosita treating plant was treating approximately 25,000 MMBtu of gas per day at the time of its acquisition. The Rosita treating plant is operated in the Partnership's Treating Division, whereas all of the other assets in the CCNG acquisition are included in the Partnership's Midstream Division.
The Partnership acquired the Vanderbilt system in December 2002 for a purchase price of $12.0 million. The Vanderbilt system consists of approximately 200 miles of gathering lines in the same approximate geographic area as the Gulf Coast System. At the time of its acquisition, the Vanderbilt system was transporting approximately 32,000 MMBtu of gas per day.
The Partnership acquired the 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 the Partnership with a new core area for growth in south central Mississippi, expanded its presence in West Texas, increased the total miles of its pipelines from 1,700 to 2,500 and enabled it to enter the business of carbon dioxide separation.
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 Enron receivable is discussed below under "-Results of Operations-Year Ended December 31, 2002 Compared to Year Ended December 31, 2001-Profit (Loss) on Energy Trading Activities." The two gas plants are the Jonesville processing plant, which had been largely inactive since the beginning of 2001, and the Clarkson plant, acquired shortly before the Partnership's initial public offering. Our management has not yet determined whether we will elect to activate or liquidate these plants. The activation or liquidation of one or both of these plants will not have a material impact on our business or results of operations.
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. We estimate that we will be able to use our net operating loss carryforward to offset most of the income allocated to us in fiscal 2004 by the Partnership. In future years, 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 stockholders will decrease markedly after we use all of our net operating loss carryforward.
Our use of this net operating loss carryforward will be limited if there is a greater than 50.0% change in our stock ownership over a three year period. However, we do not expect such a change in ownership to occur before we fully utilize our loss carryforward.
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 correlate closely with changes in the price of crude oil. NGL product and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.
Profitability under 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 the Partnership's profitability since the purchase price of a portion of the gas it buys (approximately 8.4% in 2003) 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 the Partnership buys and sells, 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, 2003. 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.
(1)Gas sold is less than gas purchased due to production of natural gas liquids.
(2)These volumes are not reflected in revenues or purchased gas cost, but are presented net as a component of profit (loss) on energy trading activities. 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 $0.7 million on an annual basis (before consideration of the hedges discussed below). As of December 31, 2003, the Partnership has hedged a portion of its exposure to such fluctuations in natural gas prices as follows for future periods:
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.
In addition to the margins generated by the Gregory gathering system, the Partnership generates revenues at its Gregory processing plant under two types of arrangements:
•For the year ended December 31, 2003, the Partnership purchased approximately 16% the natural gas volumes on its Gregory system under contracts in which it was exposed to the risk
of loss or gain in processing the natural gas. Under these contracts, the Partnership fractionates the NGLs into separate NGL products, which it then sells at prices based upon the market price for NGL products. All of the processed natural gas, up to 100,000 MMcf/d, is delivered to two customers at a price based on a fixed price relative to a monthly index. Since the Partnership extracts Btu's from the gas stream in the form of the liquids or consume it as fuel during processing, it reduces the Btu content of the natural gas but seeks to more than offset this by creating value from the separated NGL products. Accordingly, the Partnership's margins under these arrangements can be negatively affected in periods where the value of natural gas is high relative to the value of NGLs.
•For the year ended December 31, 2003, the Partnership purchased approximately 84% of the natural gas volumes on its Gregory system at a spot or market price less a discount that includes a 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. Under these contracts, the producer retains ownership of the fractionated NGLs, and accordingly bears the risk and retains the benefits associated with processing the natural gas. The Partnership anticipates purchasing increasing percentages of gas under fixed fee arrangements as opposed to contracts under which the processing economics are for its account.
The Partnership's Conroe gas plant and gathering system generates revenues based on fees it charges to producers for gathering and compression services, and it retains 40% of the NGLs produced from a portion of the gas processed at the facility.
The Partnership owns an undivided 12.4% interest in the Seminole gas processing plant, which is located in Gaines County, Texas. The Seminole plant has dedicated long-term reserves from the Seminole San Andres unit, to which it also supplies carbon dioxide under a long-term arrangement. Revenues at the plant are derived from a fee it charges producers, including those at the Seminole San Andres unit, for each Mcf of carbon dioxide returned to the producer for reinjection. The fees currently average approximately $0.59 for each Mcf of carbon dioxide returned. Reinjected carbon dioxide is used in a tertiary oil recovery process in the field. 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. In the last half of 2003, the Partnership's share of NGLs totaled 2,824,000 gallons at an average price of $0.5154 per gallon. The Partnership has entered into a one-year contract with Duke Energy NGL Services, L.P. to market the Partnership's NGLs on its behalf, and to receive its share of proceeds from the sale of carbon dioxide from the plant operator. The Partnership is separately billed by the plant operator for its share of expenses.
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, 2003 Compared to Year Ended December 31, 2002
Gross Margin. Midstream gross margin was $46.7 million for the year ended December 31, 2003 compared to $23.7 million for the year ended December 31, 2002, an increase of $23.0 million, or 97%. The largest increase in gross margin was due to the acquisition of assets from Duke Energy Field Services on June 30, 2003. These assets added gross margin of $9.4 million. The CCNG system had significant growth due to an increase in on-system volume and the addition of the Hallmark lateral, resulting in an increase in margin of $4.7 million. The Partnership acquired the Vanderbilt Gathering system on December 31, 2002; this system added gross margin of $4.4 million. Gregory gathering system and Gregory processing plant had increased margin of $2.6 million. These systems had significant growth in volume due to producer drilling activity in the area, to which the Partnership responded with the Gregory plant expansion during 2003. The Gulf Coast system had increased margin of $1.2 million despite the fact that volumes declined. The reason for the decline in volumes was because the Partnership sourced two markets from Vanderbilt the last half of 2003 that were previously sourced from the Gulf Coast system. The Partnership had an increase in volume and increase in margin due to a large customer taking gas from its system for 12 months in 2003 and only 6 months in 2002, and it had increased margin due to renegotiation of producer contracts. The Arkoma system also had increased volume, creating an increase in margin of $0.8 million.
Treating gross margin was $13.0 million for the year ended December 31, 2003 compared to $9.0 million in the same period in 2002, an increase of $4.0 million, or 44%. The increase was due to 27 new plants placed in service in 2003, which generated $3.7 million offset by 10 plants removed from service in 2003, which decreased margin by $0.8 million (a net increase of $2.9 million). In addition, an increase in volume at two plants with throughput-based contracts accounted for $1.1 million of the increase in treating margin.
Operating Expenses. Operating expenses were $17.8 million for the year ended December 31, 2003, compared to $11.4 million for the year ended December 31, 2002, an increase of $6.4 million, or 55%. An increase of $3.1 million was associated with the acquisition of assets from Duke Energy Field Services in June 2003. Costs for the Partnership's technical services support increased by approximately $0.8 million due to staff additions to operate the assets acquired in December 2002 and in June 2003 from DEFS and to manage other construction projects. The Vanderbilt system added $1.1 million to operating expenses, new treating plants increased operating expenses by $0.6 million and the Gregory Plant expansion added $0.4 million in operating expenses.
General and Administrative Expenses. General and administrative expenses were $11.6 million for the year ended December 31, 2003 compared to $7.5 million for the year ended December 31, 2002, an increase of $3.9 million, or 51%. The increase was primarily due to increases in staffing associated with the requirements of the Duke Energy Field Services acquisition and associated with the Partnership being a public entity in 2003. We also recognized an additional bad debt reserve of $1.2 million related to the Company's Enron receivable based on current recovery estimates from Enron's bankruptcy proceedings.
Impairments. The Partnership had no impairment expense in 2003 compared to $4.2 million in 2002. See "Year Ended December 31, 2002 Compared to Year Ended December 31, 2001" for a discussion of the 2002 charge.
(Profit) Loss on Energy Trading Activities. The profit on energy trading activities was $1.9 million for the year ended December 31, 2003 compared to $2.7 million for the year ended December 31, 2002, a decrease of $0.8 million, or 30%. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $2.2 million in 2003 and $1.8 million in 2002, an increase of $0.4 million, or 22%. This increase is primarily due to an increase in our producer services volumes. In addition, losses of $0.3 million and gains of $0.9 million relating primarily to options bought and/or sold in the management of the company's Enron position were booked in 2003 and 2002, respectively.
Depreciation and Amortization. Depreciation and amortization expenses were $13.5 million for the year ended December 31, 2003 compared to $7.7 million for the year ended December 31, 2002, an increase of $5.8 million, or 75%. The increase related to the Duke assets purchased in June 2003 was $2.3 million. The Vanderbilt system, purchased in December 2002 added $1.0 million of depreciation, new treating plants placed in service in 2003 resulted in an increase of $0.9 million and the Hallmark system added $0.3 million. The remaining $1.3 million increase in depreciation and amortization is a result of expansion projects and other new assets, such as the expansion of the Gregory Plant.
Interest Expense. Interest expense was $3.1 million for the year ended December 31, 2003 compared to $2.4 million for the year ended December 31, 2002, an increase of $0.7 million, or 29%. The increase relates primarily to bank debt incurred in the acquisition of the Duke assets in June, 2003 and by higher interest rates (weighted average rate of 5.35% in 2003 compared to 4.67% in 2002).
Income Tax Expense. We provide for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. Our income tax provision was $10.2 million in 2003 compared to $7.5 million in 2002, an increase of approximately $2.7 million. This increase was primarily due to the increase in the gain on issuance of units of the Partnership and the increase in
operating income. We estimate that we will not have a current tax liability in 2003 due to the availability of our net operating loss carryforward. This tax provision is reflected as an increase in our deferred tax liability.
Interest of Non-controlling Partners in the Partnership's Net Income. We recorded an expense of $5.2 million in 2003 and $99,000 in 2002 associated with the interests of non-controlling partners' in the Partnership. We owned all of the interests in the Partnership and its predecessors until its December 2002 initial public offering.
Net Income (Loss). Net income for the year ended December 31, 2003 was $13.4 million compared to $5.6 million for the year ended December 31, 2002, an increase of $7.8 million. This increase in net income was principally the result of the increase of $7.3 million in gains on issuance of units in the Partnership and the increase in gross margin of $26.9 million from 2002 to 2003, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, interest expense and income taxes as discussed above. Non-cash charges for depreciation and amortization expenses and stock based compensation also increased.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Gross Margin. Midstream gross margin was $23.7 million for the year ended December 31, 2002 compared to $17.9 million for the year ended December 31, 2001, an increase of $5.8 million, or 32%. The Corpus Christi system, the Gregory gathering system and the Gregory processing plant were acquired in May 2001. The gross margin from these assets for the 12-month period of 2002 exceeded that of the 8-month period in 2001 by $6.9 million. This was offset by lower margin of $0.8 million at the Arkoma system and $0.4 million at the Gulf Coast system due to lower prices in 2002.
Treating gross margin was $9.0 million for the year ended December 31, 2002 compared to $6.3 million for the same period in 2001, an increase of $2.7 million, or 43%. The increase was primarily due to 14 new plants placed in service in 2002, which generated $1.6 million. In addition, margin of $1.0 million was generated at two plants due to increased volume and additional margin of $0.9 million from six plants in service the entire year 2002, but were in operation only a few months in 2001. This was offset by $0.3 million decrease in margin from four plants being removed from service and another $0.3 million from contract restructuring at one treating facility.
Operating Expenses. Operating expenses were $11.4 million for the year ended December 31, 2002, compared to $7.8 million for the year ended December 31, 2001, an increase of $3.0 million, or 47%. $1.8 million of the increase was associated with the CCNG assets purchased in May 2001 and another $1.0 million was associated with growth in the treating division.
General and Administrative Expenses. General and administrative expenses were $7.7 million for the year ended December 31, 2002 compared to $5.6 million for the year ended December 31, 2001, an increase of $2.1 million, or 37%. The increases were associated with increases in staffing associated with the requirements of the CCNG assets and in preparation for the Partnership's initial public offering.
Impairments. Impairment expense was $4.2 million in 2002 compared to $2.9 million in 2001. Intangible assets were booked associated with the contract values of certain treating plants and other assets in conjunction with the Yorktown investment in May 2000. Impairment charges in 2002 and 2001 are associated with writing off certain of these intangible contract values. The charges in 2001 relate to intangible contract values associated with the Jonesville processing plant, which was
transferred out of the partnership in conjunction with the initial public offering. Impairment charges in 2002 are primarily associated with intangible contract values at 4 specific treating plants. Two of the plants are still working at the location where they were sited at the time of the Yorktown investment, but had experienced declines in cash flows. As the operator of the wells behind these plants had recently told the company that it was canceling its drilling plans in the area, the declines were expected to continue until the plants was relocated. The other two treating plants were removed from service during 2002 at the locations where they were sited at the time of the Yorktown investment, and therefore the intangible contract values associated with that particular location were deemed impaired. (One of the plants was immediately contracted at another location at a higher rental rate than previously in effect. The other plant is currently in inventory.)
(Profit) Loss on Energy Trading Activities. The profit on energy trading activities was $2.7 million for the year ended December 31, 2002 compared to a loss of $3.7 million for the year ended December 31, 2001, an increase of $6.4 million. Included in these amounts are realized margins on delivered volumes in the producer services "off-system" gas marketing operations of $1.8 million in 2002 and $1.9 million in 2001. In addition, gains of $0.9 million relating primarily to options bought and/or sold in the management of the company's Enron position were booked in 2002. Offsetting the gains from the producer services off-system gas marketing operations in 2001 was the $5.7 million reserve booked against the company's Enron receivable due to Enron Corporation's December 2001 bankruptcy.
Depreciation and Amortization. Depreciation and amortization expenses were $7.7 million for the year ended December 31, 2002 compared to $6.2 million for the year ended December 31, 2001, an increase of $1.5 million, or 25%. The increase is primarily related to additional depreciation expense associated with the CCNG assets purchased in May 2001, partially offset by a decrease in amortization expense due to goodwill no longer being amortized in 2002 in accordance with SFAS 142.
Interest Expense. Interest expense was $2.4 million for the year ended December 31, 2002 compared to $2.3 million for the year ended December 31, 2001, an increase of $0.1 million, or 6%. The increase relates primarily to bank debt incurred in the acquisitions of the CCNG assets in May 2001, offset by lower interest rates.
Gain on issuance of units in the Partnership. In conjunction with the Partnership's December 2002 initial public offering of common units, we conveyed to the Partnership our entire interest in the Partnership's predecessor in exchange for (1) a 2.0% general partner interest in the Partnership, (2) 333,000 common units and (3) 4,667,000 subordinated units of the Partnership. As a result of the Partnership issuing additional units to the public in its initial public offering at a price per unit greater than our equivalent carrying value, our share of the net assets of the Partnership increased by $11.1 million. Accordingly, we recognized an $11.1 million gain in 2002.
Income Taxes. Our income tax expense was $7.5 million for the year ended December 31, 2002, primarily due to the gain on the issuance of units in the Partnership, compared to a tax benefit of $1.3 million for the year ended December 31, 2001. As a result of the remedial allocations of Partnership deductions that will be made in favor of the holders who purchased their units on the open market, we will be allocated more taxable income relative to our distributions than other unitholders. The remedial income allocations will result in an additional current income tax provision for the year in which the allocations are made, but should correspondingly reduce the differences between the tax and book basis of the assets with respect to which remedial allocations are made, thereby reducing our deferred tax liability. At December 31, 2002, the difference in our book and tax
basis in our Partnership units was less than our share of the difference in the book and tax basis of the Partnership's assets, after considering the remedial allocations. The resulting deferred tax asset of $2.6 million can only be realized upon liquidation of the Partnership and only to the extent of capital gains. Accordingly, we have fully reserved this deferred tax asset at December 31, 2002. The amount of the deferred tax asset will change in the future when the Partnership sells additional units. The amount of future changes is dependent on the amounts of future remedial allocations and gains or losses recorded by us on the Partnership's sale of additional units.
At December 31, 2002, we had a net operating loss carry-forward of approximately $9.2 million. This carry-forward can be utilized to offset future taxable income and does not expire until 2022.
Interest of Non-controlling Partners in the Partnership's Net Income. We recorded an expense of $0.1 million during the year ended December 31, 2002 associated with the interests of non-controlling partners' in the Partnership.
Net Income (Loss). Our net income (loss) for the year ended December 31, 2002 was $5.6 million compared to ($2.7) million for the year ended December 31, 2001, an increase of $8.3 million. Gross margin increased by $8.6 million from 2001 to 2002, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, and interest expense as discussed above. The gain on issuance of units in the Partnership of $11.1 million and the profit on energy trading contracts also contributed to the increase in net income partially offset by increases in non-cash charges for depreciation and amortization expense, impairment expense and tax expense.
Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements. See Note 2 of the Notes to Combined Financial Statements.
Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services at the time the natural gas or natural gas liquids are delivered or at the time the service is performed.
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 also 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.
Prior to January 1, 2001, we used the deferral method of accounting to account for financial instruments which qualified for hedge accounting, whereby unrealized gains and losses were generally not recognized until the physical delivery required by the contracts was made.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. In accordance with SFAS No. 133, all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
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 producer services. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, the Partnership purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas. Where the Partnership takes title to the natural gas, the purchase contract is recorded as cost of gas purchased and the sales contract is recorded as revenue upon delivery.
The Partnership manages its price risk related to future physical purchase or sale commitments for producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance 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. Prior to October 26, 2002, the Partnership accounted for its producer services natural gas marketing activities as energy trading contracts in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 required energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. In October 2002, the EITF reached a consensus to rescind EITF No. 98-10. Accordingly, derivative contracts held for trading purposes entered into subsequent to October 25, 2002, should be accounted for under accrual-basis accounting rather than mark-to-market accounting unless the contracts meet the requirements of a derivative under SFAS No. 133. The Partnership's energy trading contracts qualify as derivatives, and accordingly, it continues to use mark-to-market accounting for both physical and financial contracts of its producer services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to its producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately and are reflected net in the statements of operations.
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 the Partnership's markets are located;
•the availability and prices of natural gas supply;
•the Partnership's ability to negotiate favorable sales agreements;
•the risks that natural gas exploration and production activities will not occur or be successful;
•the Partnership's dependence on certain significant customers, producers, and transporters of natural gas; and
•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. Our net cash provided by operating activities was $42.1 million for the year ended December 31, 2003 compared to cash used by operations of $5.1 million for the year ended December 31, 2002. Income before non-cash income and expenses was $27.7 million in 2003 and $14.1 million in 2002. Changes in working capital provided $14.4 million in cash flows from operating activities in 2003 and used $19.1 million in cash flows from operating activities in 2002. 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, 2003 compared to year ended December 31, 2002." Changes in working capital provided $14.4 million in cash flows in 2003 primarily due to $3.5 million in prepayments by certain customers in December 2003 combined with $3.8 million due to delays in collecting from a few large customers in December 2002 until January 2003. In addition, property cost accruals increased by approximately $1.5 million due to an increase in capital projects late in 2003 as compared to 2002. The remaining changes in working capital were due to timing of receipts and disbursements in the ordinary course of business.
Our net cash used in investing activities was $110.3 million and $33.2 million for the year ended December 31, 2003 and 2002, respectively. Net cash used in investing activities during 2003 related to the Duke acquisition ($68.1 million) as well as internal growth projects, and during 2002 primarily related to internal growth projects and the acquisitions of the Vanderbilt system ($12.0 million) and the Hallmark Lateral ($2.3 million). The primary internal growth projects referred to during 2003 were the Gregory plant expansion ($7.4 million), improvements to the Vanderbilt system ($4.7 million), and buying, refurbishing and installing treating plants ($9.9 million). The main
projects in the 2002 period were the acquisition and connection of the Hallmark system ($4.3 million), the Calpine interconnect ($1.1 million), buying, refurbishing and installing treating plants ($7.3 million), and a line extension at the Gregory plant ($0.9 million).
Our net cash provided by (used in) financing activities was $65.9 million and $41.7 million for the years ended December 31, 2003 and 2002, respectively. Financing activities in 2003 relate principally to the funding of the Duke assets acquisition and internal growth projects discussed above from bank borrowings and proceeds from the sale of common units discussed below. Financing activities during 2002 primarily represented funding or refunding of the partnership's debt and working capital needs through bank borrowings and net proceeds from our initial public offering in December 2002 and partner contributions. Financing activities also included a decrease in drafts payable of $17.1 million for the year ended December 31, 2003 and an increase in drafts payable of $25.6 million for the year ended December 31, 2002. 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, 2003 and 2002.
September 2003 Sale of Common Units. In September 2003, the Partnership completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. We received net proceeds of approximately $58.0 million, excluding an approximate $1.3 million capital contribution by our general partner. The net proceeds were used to repay borrowings outstanding under the bank credit facility of the Partnership's operating partnership.
Distributions Received from the Partnership. The following table sets forth the distributions we received from the Partnership since its initial public offering in December 2002.
(1)Reflects the pro rata minimum quarterly distribution covering the period from the closing of the Partnership's initial public offering on December 17, 2002 through December 31, 2002. This distribution was paid to us together with the March 31, 2003 distribution. Capital Requirements. The natural gas gathering, transmission, treating and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. The Partnership's capital requirements have consisted primarily of, and we anticipate will continue to be:
•maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain existing operating capacity of our assets and to extend their useful lives, or other capital expenditures which do not increase the Partnership's cash flows; and
•growth capital expenditures such as those to acquire additional assets to grow its 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, the Partnership anticipates that it will continue to invest significant amounts of capital to grow and acquire assets. The Partnership actively considers a variety of assets for potential acquisitions.
The Partnership believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.75 per quarter and to fund a portion of its anticipated capital expenditures through December 31, 2004. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below. Total capital expenditures are budgeted to be approximately $17 million in 2004. 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.
Subsequent Event. The Partnership entered into a definitive agreement on February 13, 2004 for the acquisition of the LIG Pipeline Company and its subsidiaries (LIG) from American Electric Power for $76.2 million. The acquisition will increase the Partnership's pipeline miles by approximately 2,000 miles, to a total of 4,500 pipeline miles, and increase pipeline throughput by approximately 600,000 MMBtu/d. The closing, which is subject to completion of certain conditions, is expected to occur within 90 days of the date of the definitive agreement. The Partnership will finance the acquisition through borrowings under its existing bank credit facility, issuance of additional senior notes or other financing alternatives.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2003, is as follows:
The above table does not include any physical or financial contract purchase commitments for natural gas.
Other Obligations. The Partnership receives notices from pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. Since the Partnership balances its purchases and sales in the pipelines, these allocation corrections normally have little impact to its gross margin since both the purchase and sale on the pipeline system require corrections. At December 31, 2003, the Partnership had a dispute related to one such allocation correction with a pipeline company and a customer on that pipeline. In reallocating previous settled deliveries, the pipeline company has billed the Partnership for approximately $1.2 million of gas deliveries, which occurred in the period from December 2000 through February 2001. The Partnership has, in turn, billed its customer who was over paid due to the allocation error. The Partnership's customer is disputing the timeliness of this corrected billing. The allocation error occurred prior to the acquisition by the Partnership of the subsidiary involved in the dispute. The Partnership has an indemnity from the seller for liabilities prior to the acquisition date. As of December 31, 2003, the Partnership has recorded a receivable of $1.2 million in other current receivables and a liability of $1.2 million in other current liabilities related to this allocation correction. The Partnership believes the dispute of the receivable by its customer is without merit, and further believe that the Partnership is protected against loss by its potential indemnity claim.
Description of Indebtedness
Bank Credit Facility. In June 2003 the Partnership's operating partnership, Crosstex Energy Services, L.P., entered into a $100 million senior secured credit facility with Union Bank of California, N.A. (as a lender and as administrative agent) and other lenders which was increased to $120 million in October 2003, consisting of the following two facilities:
•a $70.0 million senior secured revolving acquisition facility; and
•a $50.0 million senior secured revolving working capital and letter of credit facility.
The acquisition facility was used for the DEFS 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, 2003, $20.0 million was outstanding under the acquisition facility, leaving approximately $50.0 available for future borrowings. The acquisition facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the acquisition credit facility may be re-borrowed.
The working capital and letter of credit facility will be used for ongoing working capital needs, letters of credit, distributions to partners and general partnership purposes, including future acquisitions and expansions. At December 31, 2003, the Partnership had $30.3 million of letters of credit issued under the $50 million working capital and letter of credit facility, leaving approximately $19.7 million available for future issuances of letters of credit and/or cash borrowings. The aggregate amount of borrowings under the working capital and letter of credit facility is subject to a borrowing base requirement relating to the amount of the Partnership's cash and eligible receivables (as defined in the credit agreement), and there is a $25.0 million sublimit for cash borrowings. This facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the working capital and letter of credit facility may be re-borrowed. The Partnership is required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.
The obligations under the bank credit facility are secured by first priority liens on all of the Partnership's material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of its equity interests in certain of its subsidiaries, and ranks pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by certain of the Partnership's subsidiaries and by us. 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 acquisition facility and the working capital and letter of credit facility bear interest at the Partnership's operating partnership's option at the administrative agent's reference rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.00%. The applicable margin varies quarterly based on the Partnership's leverage ratio. The fees charged for letters of credit range from 1.50% to 2.00% per annum, plus a fronting fee of 0.125% per annum. The operating partnership will incur 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, limit the operating 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 its business;
•enter into certain commodity contracts;
•make certain amendments to the operating partnership's partnership agreement; and
•engage in transactions with affiliates.
The bank credit facility also contains covenants requiring us to maintain:
•a maximum ratio of total funded debt to consolidated EBITDA (each as defined in the bank credit facility), measured quarterly on a rolling four-quarter basis, of 3.75 to 1 through March 31, 2004, declining to 3.5 to 1 beginning June 30, 2004, pro forma for any asset acquisitions;
•a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four quarter basis, equal to 3.50 to 1;
•minimum current ratio (as defined in the credit agreement), measured quarterly, of 1 to 1; and
•a minimum tangible net worth (as defined in the credit agreement) of $60 million, plus one-half of certain equity contribution proceeds received after December 31, 2002.
Each of the following will be an event of default under the Partnership's 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 the Partnership or any of its subsidiaries, in excess of certain allowances;
•certain ERISA events involving the Partnership or its subsidiaries;
•cross defaults to certain material indebtedness;
•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 operating partnership of 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 operating 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.
The following is a summary of the material terms of the senior secured notes.
The notes represent senior secured obligations of the operating 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 the obligations of the Partnership's operating 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 of its equity interests in certain of its subsidiaries. The senior secured notes are guaranteed by the Partnership, the operating partnership's subsidiaries and us.
The senior secured notes are redeemable, at the operating 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 master shelf agreement relating to the notes contains substantially the same covenants and events of default as the Partnership's 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 operating partnership was in compliance with all debt covenants at December 31, 2003 and 2002.
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 the Partnership's operating partnership and its subsidiaries. This agreement appointed Union Bank of California, N.A. to act as collateral agent and authorized Union 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.
Credit Risk and Significant Customers
The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the Partnership's purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to the Partnership's overall profitability.
During the year ended December 31, 2003, the Partnership had one customer that individually accounted for more than 10% of consolidated revenues. During the year ended December 31, 2003, Kinder Morgan Tejas accounted for 20.5% of the Partnership's consolidated revenue. While this customer represents a significant percentage of consolidated revenues, the loss of this customer would not have material impact on the Partnership's results of operations.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on the Partnership's results of operations for the years ended December 31, 2001, 2002, or 2003. 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 its customers in the form of higher fees.
Environmental
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 the Partnership. See Item 1. "Business-Environmental Matters."
Recent Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement establishes standards for accounting for obligations associated with the retirement of tangible long-lived assets. This standard was adopted by us on January 1, 2003. We do not presently have any significant legal asset retirement obligations, and accordingly, the adoption of SFAS No. 143 had no impact on our results of operations or financial condition.
SFAS No 148, Accounting for Stock-Based Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123, SFAS No. 148 amends SFAS No. 123 and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. SFAS No. 148 permits two additional transition methods for entities that adopt the fair value based method, these methods allow companies to avoid the ramp-up effect arising from prospective application of the fair value based method. This Statement is effective for financial statements for fiscal years ending after December 15, 2002. We have complied with the disclosure provisions of the Statement in our financial statements.
In January 2003, the FASB issued Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ended after December 15, 2002. The adoption of this statement had no impact on our results of operations or financial condition.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No 51. In December 2003, the FASB issued FIN No. 46R which
clarified certain issues identified in FIN 46. FIN No. 46R requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after March 15, 2004. We are currently evaluating our ownership interests in joint ventures and limited partnerships that are currently accounted for using the equity method of accounting to determine whether FIN No. 46R will require the consolidation of any of these investments, however, we currently believe that one of the Partnership's joint venture interests, as described in Note 5 to the financial statements, will be consolidated in our financial statements when FIN No. 46R is adopted in March 2004.
The FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," ("SFAS No. 150") in May 2003. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. We have no financial instruments which are subject to SFAS No. 150.
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 31E 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 "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. In addition to specific uncertainties discussed elsewhere in this Form 10-K, the following risks and uncertainties may affect our performance and results of operations:
•our only cash-generating assets are our partnership interests in the Partnership, and our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners;
•the value of our investment in the Partnership depends largely on the Partnership's being treated as a partnership for federal income tax purposes;
•the amount of cash distributions from the Partnership that we will be able to distribute to you will be reduced by our expenses, including federal corporate income taxes and the costs of being a public company, and reserves for future dividends;
•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;
•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;
•substantially all of our partnership interest in the Partnership are subordinated to the common units, and during the subordination period, our subordinated units will not receive any distributions in a quarter until the Partnership has paid the minimum quarterly distribution of $0.50 per unit, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, on all of the outstanding common units;
•the Partnership may not have sufficient cash after the establishment of cash reserves and payment of its general partner's fees and expenses to pay the minimum quarterly distribution each quarter;
•if the Partnership is unable to contract for new natural gas supplies, it will be unable to maintain or increase the throughput levels in its natural gas gathering systems and asset utilization rates at its treating and processing plants to offset the natural decline in reserves;
•the Partnership's profitability is dependent upon the prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile;
•the Partnership's future success will depend in part on its ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;
•since the Partnership is not the operator of certain of our assets, the success of the activities conducted at such assets are outside its control;
•the Partnership operates in very competitive markets and encounters significant competition for natural gas supplies and markets;
•the Partnership is subject to risk of loss resulting from nonpayment or nonperformance by its customers or counterparties;
•the Partnership may not be able to retain existing customers, especially key customers, or acquire new customers at rates sufficient to maintain its current revenues and cash flows;
•the construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital and subjects the Partnership to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;
•the Partnership's business is subject to many hazards and operational risks, some of which may not be covered by insurance; and
•the Partnership is subject to extensive and changing federal, state and local laws and regulations designed to protect the environment, and these laws and regulations could impose liability for remediation costs and civil or criminal penalties for non-compliance.
Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.
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 faces market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas it sells; and for the portion of the natural gas it processes and for which it has taken the processing risk, it is at risk for the difference in the value of the NGL products it produces versus the value of the gas used in fuel and shrinkage in their production. The Partnership also incurs credit risks and risks related to interest rate variations.
Commodity Price Risk. Approximately 8.4% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, the Partnership's resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. In addition, of the gas the Partnership processes at its Gregory Processing Plant, the Partnership was exposed to the processing risk on 16% of the gas it purchased during the year ended December 31, 2003. The Partnership's processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and its margins will be lower during periods when the value of gas is high relative to the value of liquids. For the year ended December 31, 2003, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have changed the Partnership's processing margin by $170,000. Changes in natural gas prices indirectly may impact the Partnership's profitability since prices can influence drilling activity and well operations and thus the volume of gas it can gather, transport, process and treat.
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 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. Hedges to protect the Partnership's processing margins are generally for a more limited time frame
than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas. Such hedges generally involve taking a long position with regard to the relevant liquids and a short position in the required volume of natural gas.
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) the Partnership's counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform, as happened in the case of the Enron loss discussed above. To the extent that 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 decreases 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 our producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to the Partnership's producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.
For each reporting period, the Partnership records the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts are also recorded in profit or loss on energy trading contracts.
Set forth below is the summarized notional amount and terms of all instruments held by the Partnership for price risk management purposes at December 31, 2003 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2004, with no single contract longer than 6 months. The Partnership's counterparties to hedging contracts include Williams Energy Services Company, Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, Duke Field Services, and Duke Energy Trading and Marketing. Changes in the fair value of the Partnership's derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes in the fair value of cash flow hedges is
recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings.
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits, and monitors the appropriateness of these limits on an ongoing basis.
Credit Risk. The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the Partnership's purchases and resales 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.
Interest Rate Risk. The Partnership is exposed to changes in interest rates, primarily as a result of its long-term debt with floating interest rates. At December 31, 2003, the Partnership had $20.0 million of indebtedness outstanding under floating rate debt. The Partnership has interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein the Partnership has swapped floating rates for fixed rates of 2.29% and the applicable margin through November 1, 2004. The impact of a 100 basis point increase in interest rates on the Partnership's debt level as of December 31, 2003 would result in an increase in interest expense and a decrease in income before taxes of approximately $41,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on the Partnership's non-hedged, floating rate debt outstanding at December 31, 2003.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Public Accountants, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages through and S-1 of this Report and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls And Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. 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, 2003 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.
There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Crosstex Energy, Inc.
The following table shows information for our executive officers and members of our board of directors. Directors are elected for three-year staggered terms. Barry E. Davis and Robert F. Murchison are in the class whose term expires in 2005; Sheldon B. Lubar and Frank M. Burke are in the class whose term expires in 2006; Bryan H. Lawrence is in the class whose term expires in 2007. Executive officers are elected for one year terms.
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 our formation. He has also served as President, Chief Executive Officer and Director of Crosstex Energy GP, LLC since July 2002. 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 holds a B.B.A. in Finance from Texas Christian University.
James R. Wales, Executive Vice President, joined us in December 1996. He has also served as Executive Vice President-Southern Division of Crosstex Energy GP, LLC since July 2002. 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, together with Barry E. Davis, participated in the management buyout of Comstock Natural Gas in December 1996, which transaction resulted in our formation. He has also served as Executive Vice President-Northern and Treating Divisions of
Crosstex Energy GP, LLC since July 2002. 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, joined us in August 2000. He joined Crosstex Energy GP, LLC in July 2002 and serves as its Executive Vice President-Corporate Development. For five years prior to joining us, 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 us in September 2001, and has 25 years of finance and accounting experience. He joined Crosstex Energy GP, LLC in July 2002 and serves as its Executive Vice President and Chief Financial Officer. Prior to joining us, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President-Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant. Mr. Davis is not related to Barry E. Davis.
Michael P. Scott, Senior Vice President, joined us in July 2001. He has also served as Senior Vice President-Technical Services of Crosstex Energy GP, LLC since July 2002. Before joining us, Mr. Scott held various positions at Aquila Gas Pipeline Corporation, including Director of Engineering from 1992 to 2001, Director of Operations from 1990 to 1992, and Director of Project Development from 1989 to 1990. Prior to Aquila, Mr. Scott held various project development and engineering positions at Cabot Corporation/Cabot Transmission, Perry Gas Processors and General Electric. Mr. Scott holds a B.S. degree in Mechanical Engineering from Oklahoma State University.
Frank M. Burke joined as a director for us in February 2004 and has served as a director for Crosstex Energy GP, LLC since August 2003. Mr. Burke has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company Ltd., a private investment company located in Dallas, Texas, since 1984. Prior to that, Mr. Burke was a partner in Peat, Marwick, Mitchell & Co. (now KPMG). He is a member of the National Petroleum Council and also serves as a director of Arch Coal, Inc., Dorchester Minerals, L.P., Kaneb Pipe Line Partners, L.P., Xanser Corporation and Kaneb Services LLC. Mr. Burke received his Bachelor of Business Administration and Master of Business Administration from Texas Tech University and his Juris
Doctor from Southern Methodist University. He is a Certified Public Accountant and member of the State Bar of Texas.
Bryan H. Lawrence, Chairman of the Board, joined in May 2000 and has served as a director for Crosstex Energy GP, LLC since the completion of its initial public offering in December 2002. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of D&K Healthcare Resources, Inc., Hallador Petroleum Company, TransMontaigne Inc., and Vintage Petroleum, Inc. (each a United States publicly traded company) and Cavell Energy Corp. (a Canadian publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor B.V., Camden Resources, Inc., ESI Energy Services Inc., Ellora Energy Inc., Dernick Resources Inc. Cinco Natural Resources Corp., Peak Energy Resources, Inc., Approach Resources, Inc., Nytis Exploration Co., and Compass Petroleum Ltd. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.
Sheldon B. Lubar joined us as a director in May 2001 and has served as a director for Crosstex Energy GP, LLC since the completion of its initial public offering in December 2002. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar has also been a Director of C2, Inc., a logistics and manufacturing company, since 1995, MGIC Investment Corporation, a mortgage insurance company, since 1991, Grant Prideco, Inc., an energy services company, since 2000, and Weatherford International, Inc., an energy services company, since 1995. Mr. Lubar holds a bachelor's degree in Business Administration and a Law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee.
Robert F. Murchison joined us as a director in February 2004 and has served as a director for Crosstex Energy GP, LLC since the completion of its initial public offering in December 2002. Mr. Murchison has been the President of the general partner of Murchison Capital Partners, L.P., a private equity investment partnership since 1992. Prior to founding Murchison Capital Partners, L.P., Mr. Murchison held various positions with Romacorp, Inc., the franchisor and operator of Tony Roma's restaurants, including Chief Executive Officer from 1984 to 1986 and Chairman of the board of directors from 1984 to 1993. He served as a director of Cenergy Corporation, an oil and gas exploration and production company, from 1984 to 1987, Conquest Exploration Company from 1987 to 1991 and has served as a director of TNW Corporation, a short line railroad holding company, since 1981 and Tecon Corporation, a holding company with holdings in real estate development, investor owned water utilities, rail car repair and the fund of funds management business, since 1978. Mr. Murchison holds a bachelor's degree in history from Yale University.
"Independent" Directors
Messrs. Burke, Lubar and Murchison qualify as "independent" in accordance with the published listing requirements of The NASDAQ Stock Market (NASDAQ). The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the
company and has not engaged in various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
In addition, the members of our Audit Committee of the board of directors will each qualify as "independent" under standards established by the Securities and Exchange Commission (SEC) for members of audit committees, and the Audit Committee will include at least one member who is determined by the board of directors to meet the qualifications of an "audit committee financial expert" in accordance with SEC rules, including that the person meets the relevant definition of an "independent" director. Because we recently completed our initial public offering, we have one-year from the date of our initial listing on the Nasdaq National Market to have three members on our Audit Committee. We currently have one member, Mr. Burke, on our Audit Committee and he qualifies as "independent." Mr. Burke has been determined to be an audit committee financial expert. Shareholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Burke's experience and understanding with respect to certain accounting and auditing matters. The designation does not impose on Mr. Burke any duties, obligations or liability that are greater than are generally imposed on him as a member of the Audit Committee and board of directors, and his designation as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.
Board Committees
Our board of directors currently has, and appoints the members of, standing Audit and Compensation Committees. Each member of the Audit and Compensation Committees is an independent director in accordance with NASDAQ standards described above. Each of the board committees has a written charter approved by the board. Copies of the charter will be provided to any person, without charge, upon request. Contact Kathie Keller at 214-721-9327 to request a copy of a charter or send your request to Crosstex Energy, Inc., Attn: Kathie Keller, 2501 Cedar Springs, Suite 600, Dallas, Texas 75201.
Our Audit Committee, currently comprised of Mr. Burke, assists the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors. Mr. Burke is the Chairman of our Audit Committee. Because we recently completed our initial public offering, we have one-year from the date of our initial listing on the Nasdaq National Market to have three members on our Audit Committee.
Our Compensation Committee, comprised of Messrs. Lubar and Murchison, oversees compensation decisions for our officers as well as the compensation plans described herein.
Code of Ethics
We adopted a Code of Business Conduct and Ethics applicable to all officers, and 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. It 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 Kathie Keller at 214-721-9327 to request a copy of a charter or send your request to Crosstex Energy, Inc., Attn: Kathie Keller, 2501 Cedar Springs, Suite 600, 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.
Section 16(a)-Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors and certain officers and any 10% beneficial owners of our common stock to send reports of their beneficial ownership of common stock and changes in beneficial ownership to the Securities and Exchange Commission. We were not a public company in fiscal 2003 and therefore no Section 16(a) filings were required.
Item 11.
Item 11. Executive Compensation
The following table sets forth information concerning the compensation by us and the Partnership (and its predecessor) for our chief executive officer and the five other most highly compensated executive officers in 2002 and 2003.
Summary Compensation Table
(1)Executive officers received equity-based awards received under the Crosstex Energy GP, LLC Long-Term Incentive Plan. Employment Agreements
The executive officers of Crosstex Energy GP, LLC, including Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, have entered into employment agreements with Crosstex Energy, L.P. The following is a summary of the material provisions of those employment agreements. All of these employment agreements are substantially similar, with certain exceptions as set forth below.
Each of the employment agreements has an initial term that expires two years from the effective date, but will automatically be extended such that the remaining term of the agreements will not be less than one year. The employment agreements provide for a base annual salary of $218,400, $187,200, $187,200, $176,00, $176,000 and $156,000 for Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, respectively, for 2004.
Except in the event of Crosstex Energy, L.P.'s becoming bankrupt or ceasing operations, termination for cause or termination by the employee other than for good reason, the employment agreements provide for continued salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement. If a change in control occurs during the term of an employee's employment and either party to the agreement terminates the employee's employment as a result thereof, the employee will be entitled to receive salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement.
The employment agreements also provide for a noncompetition period that will continue until the later of one year after the termination of the employee's employment or the date on which the employee is no longer entitled to receive severance payments under the employment agreement. During the noncompetition period, the employees are generally prohibited from engaging in any business that competes with us or our affiliates in areas in which we conduct business as of the date of termination and from soliciting or inducing any of our employees to terminate their employment with us or accept employment with anyone else or interfere in a similar manner with our business.
Long-Term Incentive Plan
We adopted a long-term incentive plan for our employees, directors and affiliates who perform services for us.
The plan provides for the discretionary grant of incentive stock options, within the meaning of Section 422 of the Internal Revenue Code of 1986, to employees and for the grant of nonqualified stock options, stock appreciation rights, dividend equivalents, restricted stock and other incentive awards to employees, outside directors and consultants. The 2004 plan provides that we cannot issue incentive stock options after ten years from the date of the board's adoption of the plan. The plan was an amendment and restatement of our 2000 Stock Option Plan.
The compensation committee of our board of directors administers the plan. The administrator has the power to determine the terms of the options or other awards granted, including the exercise price of the options or other awards, the number of shares subject to each option or other award (up to 100,000 per year per participant), the exercisability thereof and the form of consideration payable upon exercise. In addition, the administrator has the authority to amend, suspend or terminate the plan, provided that no such action may affect any share of common stock previously issued and sold or any option previously granted under the plan without the consent of the holder.
The exercise price of all incentive stock options granted under the plan must be at least equal to 100% of the fair market value of the common stock on the date of grant. The exercise price of nonqualified stock options and other awards granted under the plan is determined by the administrator, but the exercise price must be at least 50% of the fair market value of the common stock on the date of grant. The term of all options granted under the plan may not exceed ten years.
Each option and other award is exercisable during the lifetime of the optionee only by such optionee. Options granted under the plan must generally be exercised within three months after the
end of optionee's status as an employee, director or consultant, or within one year after such optionee's termination by disability or death, respectively, but in no event later than the expiration of the option's term.
The plan provides that in the event of a merger of our company (other than a merger whereby Yorktown Partners LLC or its affiliates cease to own a controlling interest in us) all options and other awards shall, in the discretion of the administrator, be subject to adjustment to reflect any changes in our outstanding common stock. In addition, the plan provides that a "change of control" shall be deemed to have occurred if (i) Yorktown Partners LLC or its affiliates including any funds under its management no longer directly or indirectly owns a controlling interest in us, other than as a result of a firm commitment underwritten public offering, (ii) any sale or other disposition of all or substantially all of our assets to any person, other than our affiliates, or (iii) any merger, reorganization, consolidation or other transaction pursuant to which more than 50% of the combined voting power of the equity interests in us ceases to be owned by persons owning such interests as of the closing of this offering. Immediately prior to a change of control, all awards granted under the plan shall automatically vest and become payable or exercisable, as the case may be, in full. In this regard, all restriction periods shall terminate and all performance criteria, if any, shall be deemed to have been achieved at the maximum level. To the extent that certain awards are not exercised upon a change of control, the administrator may, in its discretion, cancel such award without payment or provide for a replacement award with respect to such property and on such terms as it deems appropriate.
Options granted under our 2000 Stock Option Plan prior to its amendment and restatement provide that if the holder of an option voluntarily terminates his or her employment with us due to the occurrence of a "change of control," such holder will be entitled to exercise the portion of the option that would have vested through the date of such voluntary termination. Under the 2000 Stock Option Plan, a "change of control" is defined as: (i) a sale of all or substantially all of our assets, (ii) a sale of all or more than 50% of our outstanding equity interests or (iii) any merger, consolidation, or reorganization where we are not the surviving corporation and, after the merger, more than 50% of the combined voting power of the equity interests in us ceases to be owned by persons owning such interests immediately prior to the merger.
Option Grants
There were no stock options granted to the named executive officers in 2003.
Option Exercises and Year-End Option Values
Crosstex Energy, Inc. The following table provides information about the number of shares issued upon option exercises by our named executive officers during 2003, and the value realized by our executive officers. The table also provides information about the number and value of options that were held by our named executive officers at December 31, 2003.
Aggregated Option Exercise in Last Fiscal Year
and Fiscal Year End Option Values
(1)The options expire on May 5, 2005. The options for Messrs. Barry E. Davis, Aulds and Wales have vested. The options for Mr. William W. Davis vest at a rate of one-third per year on each anniversary of October 1, 2001. The options for Mr. Lafield vest at a rate of one-third per year on each anniversary of May 1, 2001. The options for Mr. Scott vest at a rate of one-third per year on each anniversary of July 23, 2001.
(2)Based on the $19.50 per share initial public offering price of our common stock on January 13, 2004, less the option exercise price. The option exercise price for Messr.'s Barry E. Davis, Aulds, Wales and Lafield is $5. Crosstex Energy, L.P. The following table provides information about the number of units issued upon option exercises by Crosstex Energy, L.P.'s named executive officers during 2003, and the value realized by the Partnership's named executive officers. The table also provides information about the number and value of options that were held by the named executive officers at December 31, 2003.
Aggregated Option Exercise in Last Fiscal Year
and Fiscal Year End Option Values
The closing price for the Crosstex Energy, L.P. common units was $41.30 on December 31, 2003, the last trading day of 2003.
Compensation of Directors
Prior to 2004, our directors generally did not receive compensation for services provided as a director. Beginning in 2004, each non-employee director will be paid an annual retainer fee of $25,000. Directors may elect to receive their annual retainer in cash or in shares of restricted stock or options to purchase shares of common stock. If a director elects to receive shares of restricted stock, each share will be valued at the average of the closing prices of our common stock in the first quarter of 2004. If a director elects to receive options, the director will receive options to acquire 2.5 times the number of restricted shares that the director would have been eligible to receive at an exercise price equal to the average closing price of the stock in the first quarter of 2004. Directors will not receive an attendance fee for each board meeting, but an attendance fee of $1,000 will be paid to each director for each committee meeting he attends, except the audit committee members who will receive $1,250 for each audit committee meeting; provided that with respect to directors who are members of the same committees for both our board directors and the board of directors of Crosstex Energy GP, LLC, such director will receive 150% of the normal meeting fee for meetings for both companies' committees that occur on the same date and the cost will be split evenly between both companies. Each committee chairman will receive $2,500 annually except for the audit committee chairman who will receive $3,500 annually; provided that with respect to directors who are the chair of the same committees for both our board of directors and the board of directors of Crosstex Energy GP, LLC, such director will receive 150% of the chairman's annual fee and the cost will be split evenly between both companies. Each of our independent directors received a one-time grant of options to acquire 10,000 shares of common stock at an exercise price of $19.50. Further, we have entered into indemnity agreements with each of our directors.
Compensation Committee Interlocks And Insider Participation
The Compensation Committee of our board of directors determines compensation of the executive officers. Sheldon B. Lubar and Robert F. Murchison have served as members of the Compensation Committee of our board of directors since the completion of our initial public offering.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table shows the beneficial ownership of our common stock as of February 28, 2004, held by:
•each person who beneficially owns 5% or more of the shares of common stock then outstanding;
•each of our directors;
•each of our executive officers; and
•all of our directors and executive officers as a group.
*Less than 1%.
(1)Unless otherwise indicated, the address of each person listed above is 2501 Cedar Springs, Suite 600, Dallas, Texas 75201.
(2)The address for Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. is 410 Park Avenue, New York, New York 10022.
(3)Sheldon B. Lubar is a general partner of Lubar Nominees, and may be deemed to beneficially own the shares held by Lubar Nominees.
(4)Ownership percentage for such individual or group includes shares issuable pursuant to stock options which are presently exercisable or exercisable within 60 days including 40,000 shares for Mr. Barry E. Davis, 85,000 shares for Mr. Wales, 60,000 shares for Mr. Aulds, 31,003 shares for Mr. Lafield, 33,333 shares for Mr. William W. Davis, 26,667 shares for Mr. Scott and 276,003 shares for all directors and executive officers as a group.
(5)Bryan H. Lawrence is a member and a manager of the general partner of both Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P.
Equity Compensation Plan Information
(1)We adopted and maintain a Long Term Incentive Plan for our officers, employees and directors. See Item 11. "Executive Compensation-Long-Term Incentive Plan."
(2)The exercise prices for outstanding stock options under the plan as of December 31, 2003 range from $5.00 to $7.00.
(3)Our Long Term Incentive Plan for our officers, employees and directors was approved by our security holders prior to our initial public offering.
Item 13.
Item 13. Certain Relationships and Related Transactions
Relationship with Crosstex Energy, L.P.
General. We indirectly own 333,000 common units and 4,667,000 subordinated units representing an aggregate 54.3% limited partnership interest in the Partnership. The Partnership's general partner owns a 2% general partner interest in the Partnership and the incentive distribution rights. The general partner's ability, as general partner, to manage and operate Crosstex Energy, L.P. and our ownership of an aggregate 54.3% limited partner interest in the Partnership effectively gives the general partner the ability to veto some of the Partnership's actions and to control the Partnership's management.
Omnibus Agreement. Concurrent with the closing of the Partnership's initial public offering, we entered into an agreement with the Partnership, Crosstex Energy GP, LLC and the general partner which governs potential competition among us and the other parties to the agreement. We agreed, and caused our controlled affiliates to agree, for so long as management, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. and its affiliates, or any combination thereof, control the Partnership's general partner, not to engage in the business of gathering, transmitting, treating, processing, storing and marketing of natural gas and the transportation, fractionation, storing and marketing of NGLs unless it first offers the Partnership the opportunity to engage in this activity or acquire this business, and the board of directors of Crosstex Energy GP, LLC, with the concurrence of its conflicts committee, elects to cause the Partnership not to pursue such opportunity or acquisition. In addition, we have the ability to purchase a business that has a competing natural gas gathering, transmitting, treating, processing and producer services business if the competing business does not represent the majority in value of the business to be acquired and we offer the Partnership the opportunity to purchase the competing operations following their acquisition. The noncompetition restrictions in the omnibus agreement do not apply to the assets retained and
business conducted by us at the closing of the Partnership's initial public offering. Except as provided above, our controlled affiliates are not prohibited from engaging in activities in which they compete directly with the Partnership. In addition, Yorktown Energy Partners IV, L.P., Yorktown Energy Partners V, L.P. and any affiliated Yorktown funds are not prohibited from owning or engaging in businesses which compete either with us or the Partnership.
Renunciation of Opportunities
In our restated charter and in accordance with the 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 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
•to two affiliated stockholders with a controlling 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.
Crosstex Energy, LP.'s General Partner
The Partnership's general partner does not receive any management fee or other compensation in connection with its management of the Partnership's business, but it is reimbursed for all direct and indirect expenses incurred on its behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to the Partnership, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. The partnership agreement provides that the general partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. For the twelve months ended December 31, 2003, the amount which the Partnership reimbursed the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on its behalf could not exceed $6.0 million. This reimbursement cap did not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on behalf of the partnership. The $6.0 million limit on such reimbursements expired in December 2003 and future expenses reimbursed by the Partnership wil be higher.
The Partnership's general partner owns a 2% general partner interest in the Partnership and all of the incentive distribution rights. The Partnership's general partner is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds levels specified in the partnership agreement. Under the quarterly incentive distribution provisions, generally the general partner is entitled to 13% of amounts the Partnership distributes in excess of $0.50 per unit, 23% of the amounts the Partnership distributes in excess of $0.625 per unit and 48% of amounts the Partnership distributes in excess of $0.75 per unit.
Indemnification of Directors and Officers
Section 145 of the Delaware General Corporation Law permits indemnification of officers, directors and other corporate agents under specific circumstances and subject to specific limitations. Our restated certificate of incorporation and restated bylaws provide that we shall indemnify our directors and officers to the full extent permitted by the Delaware General Corporation Law, including in circumstances in which indemnification is otherwise discretionary under Delaware law.
We have entered into indemnification agreements with our directors and executive officers that provide the maximum indemnity allowed to directors and executive officers by Section 145 of the Delaware General Corporation Law, as well as certain additional procedural protections. The indemnity agreements provide that directors will be indemnified to the fullest extent not prohibited by law against all expenses (including attorney's fees) and settlement amounts paid or incurred by them in any action or proceeding as our directors or executive officers, including any action on account of their services as executive officers or directors of any other company or enterprise when they are serving in such capacities at our request, and including any action by us or in our right. In addition, the indemnity agreements provide for reimbursement of expenses incurred in conjunction with being a witness in any proceeding to which the indemnitee is not a party. We must pay in advance of a final disposition of a proceeding or claim the expenses incurred by the indemnitee no later than 10 days after our receipt of an undertaking by or on behalf of the indemnitee, to repay the amount of the expenses to the extent that it is ultimately determined that the indemnitee is not entitled to be indemnified by us. The indemnity agreements also provide the indemnitee with remedies in the event that we do not fulfill our obligations under the indemnity agreements.
Section 102(b)(7) of the Delaware General Corporation Law permits a corporation to provide in its certificate of incorporation that a director of the corporation shall not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for payments of unlawful dividends or unlawful stock repurchases or redemptions, or (iv) for any transaction from which the director derived an improper personal benefit. Our restated certificate of incorporation provides for that limitation of liability.
We maintain policies of insurance under which our directors and officers are insured, within the limits and subject to the limitations of the policies, against specific expenses in connection with the defense of, and specific liabilities which might be imposed as a result of, actions, suits or proceedings to which they are parties by reason of being or having been directors or officers.
Option Cancellation
In 2003, Jack M. Lafield received $93,236 as consideration for the cancellation of 13,496 options to purchase our common stock which had been previously granted under our 2000 Stock Option Plan.
Registration Rights
In October 2003, we entered into an Agreement Regarding 2003 Registration Statement and Waiver and Termination of Stockholders' Agreement whereby we granted certain registration rights to our stockholders, including certain of our directors and all of our officers, for shares of our common stock.
According to the terms of a registration rights agreement effective upon our initial public offering, Yorktown Energy Partners V, L.P., Lubar Nominees and all of our officers will be entitled to demand registration rights for the 9,427,348 shares of our capital stock outstanding prior to our initial public offering and any shares acquired by such persons in connection with the exercise of stock options. The stockholders must exercise their demand for registration by delivering a written request to us. We shall not be required to effect more than two registration statements for our officers, and we shall not be required to effect more than four registration statements for Yorktown Energy Partners IV, L.P., Yorktown Energy Partners V, L.P. and Lubar Nominees. If our board of directors determines a demand registration would have an adverse effect on us, we may delay any demand registration for a period not to exceed 90 days. We are also not required to effect more than two registrations in any 12-month period. In addition, these stockholders may participate in any public offering by us of our common stock, other than this offering or an offering under a registration statement on Form S-4 or Form S-8 or any other forms not available for registering capital stock for the sale to the public, subject to marketing considerations as determined by our managing underwriter for that offering. We will pay all expenses in connection with any registration under this agreement. This agreement terminates to each stockholder when all of the stockholders' shares have been registered pursuant to the Securities Act of 1933 and sold or sold under Rule 144 to the Securities Act of 1933.
Other Related Party Transactions
Camden Resources, Inc. The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. Yorktown Energy Partners IV, L.P. has made equity investments in both Camden and us. The gas treating and gas purchase agreements the Partnership has entered into with Camden are standard industry agreements containing terms substantially similar to those contained in the Partnership's agreements with other third parties. During the year ended December 31, 2003, the Partnership purchased natural gas from Camden Resources, Inc. in the amount of approximately $8.4 million and received approximately $190,000 in treating fees from Camden Resources, Inc.
Crosstex Pipeline Partners, L.P. The Partnership indirectly owns general and limited partner interests in Crosstex Pipeline Partners, L.P. that represent a 28% economic interest. The Partnership has entered into various transactions with Crosstex Pipeline Partners, and it believes that the terms of these transactions are comparable to those that it could have negotiated with unrelated third parties. During the year ended December 31, 2003, the Partnership's predecessor: (1) purchased natural gas from Crosstex Pipeline Partners in the amount of approximately $8.2 million and paid Crosstex Pipeline Partners approximately $41,000 for transportation of natural gas, (2) received a management fee from Crosstex Pipeline Partners in the amount of approximately $125,000 and (3) received approximately $104,000 in distributions from Crosstex Pipeline Partners
Crosstex Denton County Gathering J.V. The Partnership owns a 50% interest in Crosstex Denton County Gathering, J.V. (CDC). CDC was formed to build, own and operate a natural gas gathering system in Denton County, Texas. The Partnership manages the business affairs of CDC. The other 50% joint venture partner (the CDC Partner) is an unrelated third party who owns and operates the natural gas field in Denton County.
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.
The Partnership's investment in CDC is $2.3 million as of December 31, 2003. The Partnership also has $635,000 in receivables from affiliates for cash advances to CDC for current disbursements that are generally repaid on a month-to-month basis in the normal course of business.
During the year ended December 31, 2003, the Partnership received a management fee from CDC of $110,000.
Item 14.
Item 14. Principal Accountant Fees and Services
Audit Fees
The fees for professional services rendered for the audit of our annual financial statements for the fiscal year ended December 31, 2003 and services that are normally provided by KPMG in connection with statutory or regulatory filings or engagement for the fiscal year were $317,000. This amount also included fees associated with comfort letters and consents related to debt and equity offerings. For the fiscal year ended December 31, 2002, we did not have any similar fees to those described above. The fees for professional services rendered for the audit of Crosstex Energy, L.P.'s annual financial statements for each of the fiscal years ended December 31, 2003 and December 31, 2002, and the reviews of the financial statements included in Crosstex Energy, L.P.'s Quarterly Reports on Forms 10-Q or services that are normally provided by KPMG in connection with statutory or regulatory filings or engagement for each of those fiscal years, were $411,500 and $354,123, respectively. These amounts also included fees associated with comfort letters and consents related to debt and equity offerings of Crosstex Energy, L.P.
Audit-Related Fees
KPMG did not perform any assurance and related services related to the performance of the audit or review of our financial statements for the fiscal years ended December 31, 2003 and December 31, 2002 that were not included in the audit fees listed above.
Tax Fees
Aggregate fees billed or expected to be billed by KPMG, for tax compliance, tax advice and tax planning for each of the fiscal years ended December 31, 2003 and December 31, 2002, were $34,090 and $3,500, respectively. These fees include fees relating to reviews of tax returns, tax consulting and planning. Aggregate fees billed or expected to be billed by KPMG to Crosstex Energy, L.P. for tax compliance, tax advice and tax planning for each of the fiscal years ended December 31, 2003 and December 31, 2002, were $103,725 and $50,875, respectively. These fees include fees relating to reviews of tax returns, tax consulting and planning for Crosstex Energy, L.P.
All Other Fees
KPMG did not render services to us, other than those services covered in the sections captioned "Audit Fees," and "Tax Fees" for the fiscal years ended December 31, 2003 and December 31, 2002.
Audit Committee Approval of Audit and Non-Audit Services
We were not a public company in 2003 and did not have an Audit Committee. For 2004, the Audit Committee has pre-approved the use of KPMG for specific tax-related services. In such case, the Audit Committee has also set a specific annual limit on the amount of such tax-related services which we will obtain from KPMG, and has required management to report the specific engagements
to the Audit Committee. All other non-audit services other than the pre-approved services set forth above and any services that exceed the annual limits set forth in the policy must be pre-approved by the Audit Committee. The Chairman of the Audit Committee is authorized by the Audit Committee to pre-approve additional KPMG audit and non-audit services between Audit Committee meetings; provided that the additional services do not affect KPMG's independence under applicable Securities and Exchange Commission rules and any such pre-approval is reported to the Audit Committee at its next meeting.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)Financial Statements and Schedules
(1)See the Index to Financial Statements on page.
(2)See Schedule II-Valuation and Qualifying Accounts on Page S-1.
(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):
10.1
-
Omnibus Agreement, dated December 17, 2002, among Crosstex Energy, Inc. and certain other parties (incorporated by reference from Exhibit 10.5 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.2*
-
Form of Indemnity Agreement, entered into with directors and/or officers on December 31, 2003
10.3+
-
Crosstex Energy GP, LLC Long-Term Incentive Plan dated July 12, 2002 (incorporated by reference from Exhibit 10.4 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.4*
-
Agreement Regarding 2003 Registration Rights Agreement and Termination of Stockholders' Agreement, dated October 27, 2003
10.5*+
-
Crosstex Energy, Inc. Long-Term Incentive Plan, dated December 31, 2003
10.6*
-
Registration Rights Agreement, dated December 31, 2003
10.7
-
Second Amended and Restated Credit Agreement, dated November 26, 2002, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated reference from Exhibit 10.1 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.8
-
First Amendment to Second Amended and Restated Credit Agreement dated as of June 3, 2003, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated by reference from Exhibit 10.2 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-106927, filed July 10, 2003)
10.9
-
Second Amendment to Second Amended and Restated Credit Agreement, dated as of June 3, 2003, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 10, 2004)
10.10
-
$50,000,000 Senior Secured Notes Master Shelf Agreement as of June 3, 2003 (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-106927, filed July 10, 2003)
10.11
-
First Contribution, Conveyance and Assumption Agreement dated November 27, 2002, among Crosstex Energy, L.P. and certain other parties (incorporated by reference from Exhibit 10.2 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.12
-
Closing Contribution, Conveyance and Assumption Agreement dated December 11, 2002, among Crosstex Energy, L.P. and certain other parties (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.13
-
Crosstex Energy Holdings Inc. 2000 Stock Option Plan (incorporated by reference from Exhibit 10.14 to Amendment No. 2 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed December 30, 2003)
21.1
-
List of Subsidiaries (incorporated by reference from Exhibit 21.1 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
31.1*
-
Certification of the principal executive officer
31.2*
-
Certification of the principal financial officer
32.1*
-
Certification of the principal executive officer and the principal financial officer of the Company pursuant to 18 U.S.C. Section 1350
*Filed herewith.
+Compensatory benefit plan or arrangement in which directors and executive officers are eligible to participate.
(b)Reports on Form 8-K.
Registrant did not file any Current Reports on Form 8-K during the fourth quarter of 2003.
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 26 day of March 2004.
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 in the capacities indicated.
Signature
Title
Date
/s/ BARRY E. DAVIS Barry E. Davis
President, Chief Executive Officer and Director (Principal Executive Officer)
March 26, 2004
/s/ FRANK M. BURKE Frank M. Burke
Director
March 26, 2004
/s/ BRYAN H. LAWRENCE Bryan H. Lawrence
Chairman of the Board
March 26, 2004
/s/ SHELDON B. LUBAR Sheldon B. Lubar
Director
March 26, 2004
/s/ ROBERT F. MURCHISON Robert F. Murchison
Director
March 26, 2004
/s/ WILLIAM W. DAVIS William W. Davis
Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
March 26, 2004
Independent Auditors' Report
To the Stockholders of
Crosstex Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Crosstex Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2003 and 2002, 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, 2003. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedules as listed in the accompanying index. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Crosstex Energy, Inc. and subsidiaries as of December 31, 2003 and 2002, and the consolidated results of their operations, comprehensive income and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. 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.
As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Partnership changed its method of accounting for derivatives. Also, as explained in note 2 to the financial statements, effective January 1, 2002, the Company changed its method of amortizing goodwill.
/s/ KPMG LLP
Dallas, Texas,
February 26, 2004
CROSSTEX ENERGY, INC.
Consolidated Balance Sheets December 31, 2003 and 2002
(In thousands, except share data)
See accompanying notes to consolidated financial statements
CROSSTEX ENERGY, INC.
Consolidated Statements of Operations
(In thousands, except share data)
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Changes in Stockholders' Equity
(In thousands, except share data)
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Consolidated Statements of Comprehensive Income December 31, 2003, 2002 and 2001
(In thousands)
See accompanying notes to consolidated financial statements
CROSSTEX ENERGY, INC.
Consolidated Statements of Cash Flows
(In thousands)
See accompanying notes to consolidated financial statements.
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements December 31, 2003 and 2002
(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. 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)Organization, Public Offering of Units 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. On December 17, 2002, the Partnership completed an initial public offering of common units representing limited partner interests in the Partnership. Prior to its initial public offering, the Partnership was an indirect wholly owned subsidiary of the Company. The Company conveyed to the Partnership its indirect wholly owned ownership interest in Crosstex Energy Services, Ltd. (CES) in exchange for (i) a 2% general partner interest (including certain Incentive Distribution Rights) in the Partnership, (ii) 333,000 common units and (iii) 4,667,000 subordinated units of the Partnership, together representing a 67.1% limited partner interest. Prior to the conveyance of CES to the Partnership, CES distributed certain assets to the Company including (i) the Jonesville and Clarkson gas plants, (ii) the Enron receivable, and (iii) the right to receive a cash distribution of $2.5 million. As a result of CELP issuing additional units to unrelated parties, the Company's share of net assets of CELP increased by $11.1 million. Accordingly, the Company recognized a $11.1 million gain in 2002. See Note 3 for a discussion of the Partnership's September 2003 sale of additional common units.
CES constitutes the Partnership's predecessor. The transfer of ownership interests in CES to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Accordingly, the accompanying financial statements include the historical results of operations of CES prior to transfer to the Partnership.
As of December 31, 2003, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. (collectively, Yorktown) owned 77% of CEI and CEI management and directors owned 23% of CEI. In January 2004, CEI 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. CEI's existing shareholders sold 2,306,000 common shares (on a post-split basis) and CEI 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. CEI's existing stockholders also repaid approximately $4.9 million in stockholder notes receivable in connection with the public offering. After giving effect to this public offering,
Yorktown owns 60.2% of CEI's outstanding common shares, CEI management and directors own 17.8% of CEI's common shares and the remaining 22.0% 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. 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 requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. See discussion of Enron account receivable in Note 10.
(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)Property, Plant, and Equipment Property, plant and equipment consists of intrastate gas transmission systems, gas gathering systems, industrial supply pipelines, natural gas processing plants, an undivided 12.4% interest in a carbon dioxide processing plant, and gas treating plants..
Other property and equipment is primarily comprised of furniture, fixtures, and office equipment. Such items are depreciated over their estimated useful life of five years. Property, plant and equipment 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. 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. Impairments of approximately $4.2 million and $2.9 million associated with certain assets and the related intangible assets were recorded in the years ended December 31, 2002 and 2001, respectively. The impairments recorded in 2002 and 2001 relate primarily to customer relationships recorded as intangible assets as part of CES's formation. Due to changes impacting the expected future cash flows of the related assets, the Company determined the intangible assets were impaired under SFAS No. 121 or SFAS No. 144.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions 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.
(d)Amortization of Intangibles Until January 1, 2002, goodwill was amortized on a straight-line basis over 15 years.. Such amortization was $390,000 for the year ended December 31, 2001. The Company discontinued the amortization of goodwill effective January 1, 2002 with the adoption of SFAS No. 142. As of December 31, 2003, accumulated amortization of goodwill was $674,000.
The following table shows the Company's net earnings excluding goodwill amortization for the year ended December 31, 2001 (in thousands except per share data).
The Company has approximately $6.2 million of goodwill at December 31, 2003 which resulted from the Company's formation in May 2000. The goodwill has been allocated to the Midstream segment and is assessed at least annually for impairment. During the fourth quarter of 2003, the Company completed the annual impairment testing of goodwill and no impairment was required.
Intangible assets are amortized on a straight-line basis over the expected benefits of the customer relationships, which average six years. Such amortization was $896,000, $454,000 and $772,000 for the years ended December 31, 2003, 2002 and 2001, respectively. See impairment of intangibles discussed in note 2(d). As of December 31, 2003, accumulated amortization of intangible assets was $2,089,000.
(e)Other Assets Unamortized debt issuance costs totaling $2.1 million as of December 31, 2003 are included in other non-current assets. Debt issuance costs are amortized into interest expense over the term of the related debt. Other non-current assets as of December 31, 2003 also include the non-current portion of the note receivable from Adkins discussed in Note 5.
(f)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 $212,000 and $149,000 and an imbalance receivable of $447,000 and $79,000 at December 31, 2003 and 2002, respectively. Imbalance receivables are carried at the lower of costs or market value.
(g)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).
(h)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. The impact of adopting SFAS 133 on January 1, 2001, was to record the fair value of derivatives as a liability in the amount of $1,006,000 ($654,000 net of taxes).
Currently, all derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. These instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in other comprehensive income in stockholders' equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. The asset or liability related to the derivative instruments is recorded on the balance sheet in fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.
(i)Producer 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 Producer 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 natural gas marketing 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. Prior to October 26, 2002, the Company accounted for its Producer Services natural gas marketing activities as energy trading contracts in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 required energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. In October 2002, the EITF reached a consensus to rescind EITF No. 98-10. Accordingly, energy trading contracts entered into subsequent to October 25, 2002, should be accounted for under accrual accounting rather than mark-to-market accounting unless the contracts meet the requirements of a derivative under SFAS No. 133. The 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 Producer Services business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to the Company's Producer Services natural gas marketing activities are recognized in earnings as profit or loss on energy trading 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 realized gains or losses on settled contracts are reported as profit or loss on energy trading in the statements of operations.
Margins earned on settled contracts from its producer services activities included in profit (loss) on energy trading contracts in the consolidated statement of operations was $2,231,000, $1,791,000, and $1,946,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
Energy trading contract volumes that were physically settled were as follows (in MMBTUs):
(j)Comprehensive Income (Loss) During 1998, the Company adopted SAFS No. 130 ("SFAS 130"), Reporting Comprehensive Income, which establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, unrealized gains and losses on marketable securities, foreign currency translation adjustments, minimum pension liability adjustments, and effective January 1, 2001, unrealized gains and losses on derivative financial instruments.
With the adoption of SFAS No. 133 on January 1, 2001, the Company began recording deferred hedge gains and losses on its derivative financial instruments that qualify as hedges as other comprehensive income.
(k)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. As of December 31, 2003 and 2002, the reserve for doubtful accounts was approximately $6.9 million and $5.8 million, respectively. See further discussion at Note 12.
During the years ended December 31, 2003, 2002 and 2001, the Company had 1, 1, and 3 customers, respectively, which accounted for more than 10% of consolidated revenues. The relevant percentages for these customers were: (i) for the year ended December 31, 2003-20.5%; (ii) for the year ended December 31, 2002-27.5%; and (iii) for the year ended December 31, 2001-23.9%, 13.4%, and 11.5%. While these customers represent a significant percentage of revenues, the loss of any of these would not have a material adverse impact on the Company's results of operations.
(l)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 reasonably estimated. For the years ended December 31, 2003, 2002 and 2001, such expenditures were not significant.
(m)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. In addition, compensation expense is recorded on 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. Compensation expense of $5,345,000, $41,000 and $0 was recognized in 2003, 2002 and 2001, respectively. The portion of compensation expense for 2003 related to operating activities was $2,122,000 and the remaining expense of $3,223,000 related to general and administrative activities.
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):
The fair value of each option is estimated on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions used for grants in 2002 and 2001:
*Fair values and option prices have been adjusted for the two-for-one stock split made in conjuntion with the Company's January 2004 initial public offering.
No Company options were granted in 2003.
(n)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 CELP limited partnership units, to unrelated parties.
(o)New Accounting Pronouncements In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement establishes standards for accounting for obligations associated with the retirement of tangible long-lived assets. This standard was adopted by the Company on January 1, 2003. The Company does not presently have any significant asset retirement obligations, and accordingly, the adoption of SFAS No. 143 had no impact on the Company's results of operations or financial condition.
SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123, provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. SFAS No. 148 permits two additional transition methods for entities that adopt the fair value based method, these methods allow companies to avoid the ramp-up effect arising from prospective application of the fair value based method. This Statement is effective for financial
statements for fiscal years ending after December 15, 2002. The Company has complied with the disclosure provisions of the Statement in its financial statements.
In January 2003, the FASB issued FASB Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement provisions of the Interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ending after December 15, 2002. The adoption of the statement had no material effect on the Company's financial statements.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. In December 2003, the FASB issued FIN No. 46R which clarified certain issues identified in FIN 46. FIN No. 46R requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this Interpretation must be applied at the beginning of the first interim or annual period ending after March 15, 2004. The Company is evaluating its ownership interests in joint ventures and limited partnerships that are currently accounted for using the equity method of accounting to determine whether FIN No. 46R will require the consolidation of any of these investments, however, the Company currently believes that one of its joint venture interests, as described in Note 5 to the financial statements, will be consolidated in the financial statements when FIN No. 46R is adopted in March 2004.
The FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," ("SFAS No. 150") in May 2003. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Company has no financial instruments which are subject to SFAS No. 150.
(3) Public Offerings of Units by CELP and Certain Provisions of the Partnership Agreement
(a)Initial Public Offering On December 17, 2002, the Partnership completed its initial public offering of 2,300,000 common units representing limited partner interests at a price of $20.00 per common unit. Total proceeds from the sale of the 2,300,000 units were $46.0 million, before offering costs and underwriting commissions.
A summary of the proceeds received from the offering and the use of those proceeds is as follows (in thousands):
The Crosstex Energy, L.P. partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. Net income is allocated to the general partner based on incentive distributions earned for the period plus 2% of remaining net income.
(b)Sale of Additional Common Units In September 2003, the Partnership completed a public offering of 1,725,000 common units at a public offering price of $35.97 per common unit. The Partnership received net proceeds of approximately $58.0 million. The net proceeds were used to repay borrowings outstanding under the bank credit facility of our operating partnership.
(c)Limitation of Issuance of Additional Common Units During the subordination period, the Partnership may issue up to 1,316,500 additional common units or an equivalent number of securities ranking on a parity with the common units without obtaining unit-holder 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.
(d)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. 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.
(e)Early Conversion of Subordinated Units
If the Partnership meets the applicable financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after December 31, 2005, 25% of the subordinated
units will convert to common units. If the Partnership meets these tests for any three consecutive four-quarter periods ending on or after December 31, 2006, an additional 25% of the subordinated units will convert to common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.
(f)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. Under the quarterly incentive distribution provisions, generally its general partner is entitled to 13% of amounts the Partnership distributes in excess of $0.50 per unit, 23% of the amounts the Partnership distributes in excess of $0.625 per unit and 48% of amounts the Partnership distributes in excess of $0.75 per unit. Incentive distributions totaling $954,000 were earned by the Company for the year ended December 31, 2003. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.50 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.
The Partnership increased its fourth quarter distribution on its common and subordinated units to $0.75 per unit which was paid on February 13, 2004.
(4) Significant Asset Purchases and Acquisitions
On April 3, 2001, CES entered into a purchase and sale agreement with Tejas Energy NS, LLC to acquire all of the assets and operations of Tejas Texas Pipeline GP, LLC, a Delaware limited liability company, and Tejas C Pipeline LP, LLC, a Delaware limited liability company, for a total purchase price of $30,003,120, after closing adjustments. The Company recorded the net assets acquired based on relative fair values, and the Company's results of operations include the results of the acquired assets as of May 1, 2001.
The purchase price consisted of the following (in thousands):
On October 11, 2001, CES entered into a purchase and sale agreement with various individuals to acquire the common stock of Millennium Gas Services, Inc. ("Millennium") for a total of $2,124,000 after closing adjustments, which was allocated entirely to treating plants. The Company recorded goodwill and deferred tax liability in the amount of $862,000 due to the difference in book and tax basis of the assets. The Company's results of operations include the results of Millennium as of October 1, 2001.
On June 6, 2002, CES acquired 70 miles of then-inactive pipeline from Florida Gas Transmission Company for $1,500,000 in cash and a $800,000 note payable. On June 7, 2002, CES acquired the Pandale gathering system which is connected to two treating plants, one of which (the Will-O-Mills Plant) was half-owned by CES, from Star Field Services for $2,156,000 in cash. CES purchased the other one-half interest in the Will-O-Mills Plant on December 30, 2002 for $2,200,000 in cash.
On December 19, 2002, the Partnership acquired the Vanderbilt system, consisting of approximately 200 miles of gathering pipeline located near our Gulf Coast System from an indirect subsidiary of Devon Energy Corporation, for $12,000,000 cash.
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. The purchase price and allocation thereof is as follows (in thousands):
Intangible assets relate to customer relationships and will be amortized over seven years. The purchase price allocation is preliminary and may be adjusted for post-closing adjustments. Unaudited
pro forma results of operations as if the acquisition from DEFS had been acquired on January 1, 2002 are as follows (in thousands, except per share amounts):
(5) Investment in Limited Partnerships
The Partnership owns a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Company (CPC), a 20.31% interest as a limited partner in CPC, 50% interest in the J.O.B. J.V. and a 50% interest in Crosstex Denton County Gathering, J.V. (CDC). The Company accounts for its investments under the equity method, as it exercises significant influence in operating decisions as a general partner in CPC and as a 50% owner in the joint ventures. Under this method, the Company records its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them are recorded as a reduction in the Company's investment in the affiliated partnership.
CDC was formed to build, own and operate a natural gas gathering system in Denton County, Texas. The Partnership manages the business affairs of CDC. The other 50% joint venture partner (the CDC Partner) is an unrelated third party and owns and operates natural gas wells connected to the CDC gathering systems.
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. The current portion of loan receivable of $535,000 from the CDC Partner is included in current notes receivable. The remaining balance of $1,027,000 is included in other non-current assets.
The Company's investment in CDC is $2.3 million as of December 31, 2003. The Company also has $635,000 in receivables from affiliates for cash advances to CDC for current disbursements that are generally repaid on a month-to-month basis in the normal course of business. The Company's investment at risk of CDC at December 31, 2003, is approximately $4.5 million, including cash advances and the note receivable from the CDC Partner.
Summarized financial information for 100% of CDC for the year ended December 31, 2003 is as follows (in thousands):
(6) Long-Term Debt
At December 31, 2002, the Partnership had amended the secured credit facility with Union Bank of California, N.A. ("UBOC") to provide a $67.5 million credit facility consisting of a senior secured revolving acquisition facility in the aggregate principal amount of $47.5 million and a senior secured revolving working capital facility in the aggregate principal amount of $20 million.
In June 2003, CES entered into a $100 million senior secured credit facility with UBOC (as a lender and administrative agent) and four other banks, which was increased to $120 million in October 2003, consisting of the following two facilities:
•a $70.0 million senior revolving acquisition facility; and
•a $50.0 million senior secured revolving working capital and letter of credit facility.
The acquisition facility will be used to finance the acquisition and development of gas gathering, treating, and processing facilities, as well as general partnership purposes. At December 31, 2003, $20.0 million was outstanding under the acquisition facility, leaving approximately $50.0 available for future borrowings. The acquisition facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the acquisition credit facility may be re-borrowed.
The working capital and letter of credit facility will be used for ongoing working capital needs, letters of credit, distributions and general partnership purposes, including future acquisitions and expansions. At December 31, 2003, $30.3 million of letters of credit were issued under the working capital facility, leaving approximately $19.7 million available for future issuances of letters of credit, or up to $19.7 million of cash borrowings. The aggregate amount of borrowings under the working capital and letter of credit facility is subject to a borrowing base requirement relating to the amount of our cash and eligible receivables (as defined in the credit agreement), and there is a $25.0 million sub-limit for cash borrowings. This facility will mature in June 2006, at which time it will terminate and all outstanding amounts shall be due and payable. Amounts borrowed and repaid under the
working capital facility may be re-borrowed. We are required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once a year.
Our obligations under the credit facility are secured by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of our equity interests in certain of our subsidiaries, and ranks pari passu in right of payment with the senior secured notes. The credit agreement is guaranteed by certain of our subsidiaries. We may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.
Indebtedness under the acquisition facility and the working capital facility bear interest at our option at the administrative agent's reference rate plus 0.25% to 1.5% or LIBOR plus 1.75% to 3.00%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.50% to 2.00% per annum, plus a fronting fee of 0.125% per annum. We incur quarterly commitment fees based on the unused amount of the credit facilities.
The credit agreement prohibits the Partnership from declaring distributions to unit-holders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. In addition, the bank credit facility contains various covenants that, among other restrictions, limit our operating 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 its business;
•enter into certain commodity contracts;
•make certain amendments to our operating 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 funded debt to consolidated EBITDA (each as defined in the bank credit facility), measured quarterly on a rolling four quarter basis, of 3.75 to 1 through March 31, 2004, declining to 3.5 to 1 beginning June 30, 2004, pro forma for any asset acquisitions;
•a minimum interest coverage ratio (as defined in the bank credit facility), measured quarterly on a rolling four quarter basis equal to 3.50 to 1;
•a minimum current ratio (as defined in the credit agreement), measured quarterly of 1 to l; and
•a minimum tangible net worth (as defined in the credit agreement) of $60 million, plus one-half of certain equity contributions.
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 us or our 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's operating 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, our operating 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.
The following is a summary of the material terms of the senior secured notes.
The notes represent senior secured obligations of our operating 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 operating partnership under the credit facility, by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all our equity interests in certain of our subsidiaries. The senior secured notes are guaranteed by our operating partnership's subsidiaries and us.
The senior secured notes are redeemable, at our operating 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 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, 2003 and expects to be in compliance with debt covenants for the next twelve months.
Intercreditor and Collateral Agency Agreement. In connection with the execution of the master shelf agreement 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. This agreement appointed Union Bank of California, N.A. to act as collateral agent and authorized Union Bank to execute various security documents on behalf of the lenders under the bank credit facility and the initial 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 Crosstex Energy Services, L.P.'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 $800,000 to FGTC that is payable in $50,000 annual increments starting June 2003 through June 2006 with a final payment of $600,000 due in June 2007. The note bears interest payable annually at LIBOR plus 1%.
As of December 31, 2003 and 2002, long-term debt consisted of the following (in thousands):
Maturities for the long-term debt as of December 31, 2003 are as follows (in thousands):
In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement which expires on November 1, 2004. The Company has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged. The fair value of the interest rate swap at December 31, 2003 was a $209,000 liability and is included in fair value of derivative liabilities.
(7) Income Taxes
The Company provides for income taxes using the 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, 2003, the Company had a net operating loss carryforward of approximately $9.0 million. This carry-forward can be utilized to offset future taxable income and does not expire until 2023.
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 $4.4 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.
(8) Retirement Plans
The Company sponsors a single employer 401(k) plan for employees who become eligible upon the date of hire. The Company, as stated within the plan document, will make discretionary contributions at the end of the year. Contributions during 2003, 2002 and 2001 totaled $259,000, $198,000 and $116,000, 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 700,000 common units, 233,000 of which may be awarded in the form of restricted units and 467,000 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the board of directors of the Partnership's general partner.
(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, it's 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.
In May 2003, 48,000 restricted units were issued to senior management under the long-term incentive plan with an intrinsic value of $1,247,000. In September 2003, 1,075 restricted units with an intrinsic value of $39,000 were issued to a director, at his election, for his 2003 annual director fee. These restricted units vest over a five-year period and the intrinsic value of the units is amortized into stock-based compensation expense over the vesting period. The Company recognized stock-based compensation expense of $197,000 related to the amortization of these restricted units in 2003.
(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 year ended December 31, 2003 and for the period December 17, 2002 through December 31, 2002 is provided below:
Outstanding options have exercise prices ranging from $20 to $36.29 per unit and have a remaining contractual lives of 9 to 10 years at December 31, 2003.
The Company 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. In September 2003, two directors elected to receive options to purchase 5,376 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 $23.25 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 The Company has one stock-based compensation plan, the 2000 Stock Option Plan. 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. In addition, compensation expense 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 $5,041,000, $41,000, and $0 was recognized in 2003, 2002, and 2001, respectively, related to the Company's stock options.
A summary of the status of the 2000 Stock Option Plan as of December 31, 2003 and 2002, is presented in the table below (all amounts have been adjusted to reflect the two-for-one stock split made by the Company in conjunction with its January 2004 initial public offering):
All options outstanding have an exercise price ranging from $5 to $7 at December 31, 2003.
CEI 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 CEI options which have been modified is approximately 364,000. These modified options have been accounted for using variable accounting as of the option modification date. The Company accounted for the modified options as variable options until the holders elect to cash out the options or the election to cash out the options lapsed. CEI is responsible for paying the intrinsic value of the options for the holders who elect 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 remaining modified options will be accounted for as fixed options. Beginning in the first quarter of 2003, the Company recognized stock compensation expense based on the estimated fair value at period end of the options modified. The Company recognized stock-based compensation expense of approximately $5.0 million related to the variable options for the year ended December 31, 2003. As of December 31, 2003, the Company had cashed out $1,378,000 related to the modified options. The final cash out of the modified options totaling $49,000 was paid in February 2004 and is reflected in other current liabilities as of December 31, 2003. The remainder of $3,621,000 has been recorded in paid-in capital.
(e)Earnings per share and anti-dilutive computations Basic earnings per common share was computed by dividing net income less preferred dividends, 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 the conversion of preferred shares to common shares.
The following are the share amounts used to compute the basic and diluted earnings per common share (in thousands):
All outstanding common shares were included in the computation of diluted earnings per common share. Preferred stock was anti-dilutive in the year ended December 31, 2001. Preferred stock was anti-dilutive for periods where the preferred stock dividends exceeded net income.
(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 value of trade accounts receivable includes the reserve for certain Enron receivables (see Note 11).
The Company's long-term debt was comprised of borrowings under a revolving credit facility totaling $20.0 million and $21.75 million as of December 31, 2003 and 2002, 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, 2003, the Company also had borrowings totaling $40 million under senior secured notes with a weighted average interest rate of 6.93%. The carrying amount of these borrowings approximates the fair value based on market conditions as of December 31, 2003.
The fair value of derivative contracts included in assets or liabilities 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 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, 2003 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2004, with no single contract longer than 6 months. The Company's counterparties to hedging contracts include Williams Energy Services Company, Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, Duke Field Services, and Duke Energy Trading and Marketing. As discussed in note 2, changes in the fair value of the Company's derivatives related to Producer Services gas marketing activities are recorded in earnings. The effective portion of changes in the fair value of cash flow
hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings.
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.
Assets and liabilities related to Producer Services that are accounted for as energy trading contracts are included in the fair value of derivative assets and liabilities. The Company estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):
Termination of Enron Positions
On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. ("Enron"), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Enron failed to make timely payment of approximately $3.9 million for physical delivery of gas in 2001. This amount remained outstanding as of December 31, 2002. Additionally, the Company had entered into natural gas hedging and physical delivery contracts with Enron. According to the terms of the contract, Enron is liable to the Company for the mark-to-market value of all contracts outstanding on the date the Company exercised its termination right under the contracts, which totaled approximately $4.6 million. The Company has accounted for these contracts as energy trading contracts whereby changes in fair value of the fixed price purchase commitments are recognized in earnings.
The Company had offsets to the above amounts totaling approximately $0.3 million, resulting in a net amount of $8.2 million receivable from Enron at December 31, 2001. Due to the uncertainty of future collections, a charge and related allowance for 70% of the net receivable, or $5.8 million was recorded at December 31, 2001. The 30% recovery factor was management's best estimate based on current market transactions. The ultimate recovery of the Enron receivable is uncertain and may be impacted by many factors including approval of Enron's reorganization plan, litigation against Enron advisors and other third parties and the market which exists for monetizing Enron claims. Based on the reorganization plan filed by Enron in September 2003 and current negotiations with Enron, the Company expects to recover approximately $1.3 million of its receivable from Enron through the bankruptcy process. Therefore, the Company has written the receivable down to $1.3 million as of December 31, 2003. Due to the uncertainty of the timing of recovery of this receivable due to Enron's bankruptcy, the Company has classified this receivable as long-term. Further adjustments to the Enron receivable will be recognized in earnings when management believes recovery of the asset is assured or additional reserves warranted.
For the year ended December 31, 2001, the Company recorded a loss on energy trading contracts related to natural gas marketing of $5.8 million, substantially all of which relates to estimated losses on claims from Enron. This loss was partially offset by gains of $1.9 million on energy trading contracts which physically settled during 2001.
(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, 2003, 2002 and 2001, the Partnership purchased natural gas from Camden in the amount of approximately $8,416,000, $10,076,000, and $17,300,000, respectively, and received approximately $190,000, $399,000, and $737,000 in treating fees from Camden.
Crosstex Pipeline Partners, L.P.
The Partnership had related-party transactions with Crosstex Pipeline Partners, L.P. (CPP), as summarized below:
•During the years ended December 31, 2003, 2002 and 2001, the Partnership bought natural gas from CPP in the amount of approximately $8.2 million, $3.4 million and $6.5 million and paid for transportation of approximately $41,000, $27,500 and $31,000, respectively, to CPP.
•During the years ended December 31, 2003, 2002 and 2001, the Partnership received a management fee from CPP in the amount of approximately $125,000 for each year.
•During the years ended December 31, 2003, 2002 and 2001, the Partnership received distributions from CPP in the amount of approximately $104,000, $90,000 and $152,000, respectively.
Crosstex Denton County Gathering J.V.
•During the year ended December 1, 2003, the Company received a management fee from Crosstex Denton County Gathering J.V. (CDC) of $110,000. Also, see Note (5) for a discussion of loans related to CDC.
(13) Commitments and Contingencies
(a)Leases Leased office space and equipment have remaining non-cancelable lease terms in excess of one year. The following table summarizes our remaining non-cancelable future payments under operating leases as of December 31, 2003 (in thousands):
Operating lease rental expense for the years ended December 31, 2003, 2002, and 2001 was approximately $1,812,000, $951,000 and $1,200,000, respectively.
(b)Employment Agreements Each member of senior management of the Company is a party to an employment contact with the general partner. The employment agreements provide each member of senior management with severance payments in certain circumstances and prohibit each such person from competing with the
general partner or its affiliates for a certain period of time following the termination of such person's employment.
(c)Environmental Issues The Partnership acquired two assets from DEFS in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, the remediation costs associated with the Conroe site will be covered by agreements with TRC Companies and AIG. Therefore, the Company does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.
(d)Other The Company 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.
The Partnership receives notices from pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. These allocation corrections normally have little impact on the Partnership's gross margin because the Partnership balances its purchases and sales in the pipelines and both the purchase and sale on the pipeline system require corrections. At December 31, 2003, a subsidiary of the Partnership was involved in a dispute related to one such allocation correction with a pipeline company and a customer on that pipeline. In reallocating previous settled deliveries, the pipeline company billed the Partnership's subsidiary for approximately $1.2 million of gas deliveries, that occurred in the period from December, 2000 through February, 2001. The Partnership's subsidiary, in turn, billed its customer who was overpaid due to the allocation error. The customer is disputing its liability for such amount, asserting that the corrected billing was untimely.. The allocation error occurred prior to the Partnership's acquisition of the subsidiary involved in the dispute. The Company has an indemnity from the seller of the subsidiary for liabilities arising prior to the acquisition date. As of December 31, 2003, the Company has recorded a receivable of $1.2 million in other current receivables and a liability of $1.2 million in other current liabilities related to this allocation correction. The Partnership believes the customer's dispute of the receivable is without merit, and further believes that it is protected against loss by its right to indemnification.
(14) Capital Stock
(a)Convertible Preferred Stock The Company has authorized 3,500,000 shares of Convertible Preferred Stock-A, 1,000,000 shares of Convertible Preferred Stock-B and 3,000,000 shares of Convertible Preferred Stock-C, all shares with $.01 par values. At December 31, 2003 and 2002 the Company had 2,579,743 shares of Convertible Preferred Stock-A issued and outstanding. The Company issued 491,663 Convertible Preferred Stock-B shares for cash in 2001 and issued 10,000 shares for $12,000 in cash and $108,000 in shareholder notes receivable in August 2003. At December 31, 2003 and 2002 the Company had 523,899 and 513,899 shares, respectively, of Convertible Preferred Stock-B issued and outstanding. The Company issued 1,000,000 Convertible Preferred Stock-C shares for cash in 2002 and issued 20,000 shares for $28,000 in cash and $252,000 in shareholder notes receivable in August 2003. At December 31, 2003 and 2002 the Company had 1,020,000 and 1,000,000 shares of Convertible Preferred Stock-C Shares issued and outstanding for the respective periods. All preferred shares accrue dividends at a rate of 7.5% per year. The dividends can either be paid in cash or additional shares of preferred stock at the Company's election. The Company paid the 2000 and 2001 dividends in preferred stock. The Company paid the 2002 dividends in cash in June and September 2003 and paid the 2003 dividends in cash in January 2004.
In January 2004, the Company converted all its preferred stock to common stock in conjunction with its initial public offering discussed in Note 1(b).
(b)Common Stock The Company has authorized 7,000,000 shares of common stock at $.01 par value. At December 31, 2003 and 2002 the Company had 1,882,772 and 1,743,032 shares, respectively, issued and outstanding. In January 2003, certain members of management redeemed 139,740 common shares for $2.5 million ($17.89 per common share) representing management's estimate of the fair value of the stock at redemption.
In January 2004, the Company made a two-for-one stock split in conjunction with its initial public offering discussed in Note 1(b) and increased the number of authorized common shares to shares.
(c)Notes Receivable Shares of common stock and preferred stock have been sold to certain members of management in return for notes receivable. The notes receivable are guaranteed by the related stock and bear interest. The common stock and preferred stock sold to management were sold at fair value as evidenced by the price paid by third parties. Accordingly, no compensation expense has been recorded on the stock sold to management. The stockholder notes receivable have been reflected as a reduction to stockholders' equity.
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).
(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 and various other small systems. Also included in the Midstream division are the Company's Producer Services operations (note 2(i)). The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. Included in the Treating division are four gathering systems that are connected to the treating plants.
The accounting 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 or 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 are allocated to the segments on a pro rata basis based on 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.
(16) Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data is presented below.
(1)Operating income is defined as revenues less purchased gas less operating expenses.
(2)Included in the 2003 third quarter results is a $18.4 million (before taxes) gain related to the issuance of additional common units in the Partnership's September 2003 follow-on offering.
(3)Included in the 2002 first quarter results is an impairment charge of $3.2 million related to the impairment of certain intangibles related to gas plants.
(4)Included in the 2002 fourth quarter results is an impairment of $1.0 million related to the impairment of certain intangibles related to gas plants and an $11.1 million (before taxes) gain related to the issuance of additional common units in the Partnership's 2002 offering of common units.
SCHEDULE I
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED BALANCE SHEETS
(In thousands)
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
Schedule I (continued)
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF OPERATIONS
(In thousands except share data)
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
Schedule I (continued)
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOW
(In thousands)
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
SCHEDULE II
CROSSTEX ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
(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.
Item 16. Exhibits.
(a)The following documents are filed as exhibits to this registration statement:
Exhibit
3.1*
-
Restated Certificate of Incorporation of Crosstex Energy, Inc.
3.2*
-
Restated Bylaws of Crosstex Energy, Inc.
3.3
-
Certificate of Limited Partnership of Crosstex Energy, L.P (incorporated by reference from Exhibit 3.1 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
3.4
-
Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of December 17, 2002 (incorporated by reference from Exhibit 3.2 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
3.5
-
Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference from Exhibit 3.3 to Amendment No. 2 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779, filed November 4, 2002)
3.6
-
Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of December 17, 2002 (incorporated by reference from Exhibit 3.4 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
3.7
-
Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference from Exhibit 3.5 to Crosstex Energy, L.P.'s Registration Statement, file No. 333-97779, filed August 7, 2002)
3.8
-
Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference from Exhibit 3.6 to Crosstex Energy L.P.'s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
3.9
-
Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
3.10
-
Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference from Exhibit 3.8 from Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-106927, filed July 10, 2003)
3.11
-
Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
3.12
-
Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
3.13
-
Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
3.14
-
Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
3.15
-
Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
3.16
-
Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
4.1
-
Specimen Certificate representing shares of common stock (incorporated by reference from Exhibit 4.1 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
10.1
-
Omnibus Agreement, dated December 17, 2002, among Crosstex Energy, Inc. and certain other parties (incorporated by reference from Exhibit 10.5 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.2*
-
Form of Indemnity Agreement, entered into with directors and/or officers on December 31, 2003
10.3+
-
Crosstex Energy GP, LLC Long-Term Incentive Plan dated July 12, 2002 (incorporated by reference from Exhibit 10.4 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.4*
-
Agreement Regarding 2003 Registration Rights Agreement and Termination of Stockholders' Agreement, dated October 27, 2003
10.5*+
-
Crosstex Energy, Inc. Long-Term Incentive Plan, dated December 31, 2003
10.6*
-
Registration Rights Agreement, dated December 31, 2003
10.7
-
Second Amended and Restated Credit Agreement, dated November 26, 2002, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated reference from Exhibit 10.1 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.8
-
First Amendment to Second Amended and Restated Credit Agreement dated as of June 3, 2003, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated by reference from Exhibit 10.2 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-106927, filed July 10, 2003)
10.9
-
Second Amendment to Second Amended and Restated Credit Agreement, dated as of June 3, 2003, among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 10, 2004)
10.10
-
$50,000,000 Senior Secured Notes Master Shelf Agreement as of June 3, 2003 (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-106927, filed July 10, 2003)
10.11
-
First Contribution, Conveyance and Assumption Agreement dated November 27, 2002, among Crosstex Energy, L.P. and certain other parties (incorporated by reference from Exhibit 10.2 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.12
-
Closing Contribution, Conveyance and Assumption Agreement dated December 11, 2002, among Crosstex Energy, L.P. and certain other parties (incorporated by reference from Exhibit 10.3 to Crosstex Energy, L.P.'s Annual Report on Form 10-K, file No. 000-50067, filed March 25, 2003)
10.13
-
Crosstex Energy Holdings Inc. 2000 Stock Option Plan (incorporated by reference from Exhibit 10.14 to Amendment No. 2 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed December 30, 2003)
21.1
-
List of Subsidiaries (incorporated by reference from Exhibit 21.1 to Crosstex Energy, Inc.'s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
31.1*
-
Certification of the principal executive officer
31.2*
-
Certification of the principal financial officer
32.1*
-
Certification of the principal executive officer and the principal financial officer of the Company pursuant to 18 U.S.C. Section 1350
*Filed herewith.
+Compensatory benefit plan or arrangement in which directors and executive officers are eligible to participate.