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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K/A
Amendment No. 1
ý | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2003 |
OR | |
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to |
Commission file number: 000-50536
CROSSTEX ENERGY, INC.
(Exact name of registrant as specified in its charter)
| Delaware (State of organization) | 52-2235832 (I.R.S. Employer Identification No.) | |
2501 CEDAR SPRINGS, SUITE 600 DALLAS, TEXAS (Address of principal executive offices) | 75201 (Zip Code) |
(214) 953-9500
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
| Title of Each Class | Name of Exchange on which Registered | |
|---|---|---|
| None | Not applicable |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
| Title of Class |
|---|
| Common Shares |
Indicate by check mark whether registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and has been subject to such filing requirements for the past 90 days. Yeso Noý
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No ý
There were no Common Shares held by non-affiliates of the registrant on June 30, 2003.
At February 28, 2004, there were outstanding 12,079,248 Common Shares.
DOCUMENTS INCORPORATED BY REFERENCE: None.
CROSSTEX ENERGY, INC.
FORM 10-K/A
INTRODUCTORY NOTE
This Amendment No. 1 to annual report on Form 10-K/A ("Form 10-K/A") is being filed to amend our annual report on Form 10-K for the year ended December 31, 2003, which was originally filed on March 26, 2004 ("Original Form 10-K"). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of items 6, 7, 8 and 9A of Part II and item 15 of Part IV, as amended, as well as certain currently dated certifications. Unaffected items have not been repeated in this Amendment No. 1.
In July 2004, we determined that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. As a result of correcting these errors, we have restated our consolidated balance sheets as of December 31, 2002 and 2003, our consolidated statement of operations for the year ended December 31, 2002, our consolidated statements of changes in stockholders' equity for the years ended December 31, 2002 and 2003, our consolidated statement of comprehensive income for the year ended December 31, 2002 and our consolidated statement of cash flows for the year ended December 31, 2002. We have also restated our notes to consolidated financial statements as necessary to reflect the adjustments. The net effect of the adjustments resulted in a reduction in net income and comprehensive income for the year ended December 31, 2002 by $0.4 million and a reduction in stockholders' equity and working capital as of December 31, 2002 and 2003 by $0.4 million. Please read note 2 to the accompanying consolidated financial statements for a discussion of the adjustments.
This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the adjustments described above. Such events include, among others, the events described in our quarterly report on Form 10-Q for the quarter ended March 31, 2004 and the events described in our current reports on Form 8-K filed after the filing of the Original Form 10-K. We will file with the Securities and Exchange Commission an amendment to our quarterly report on Form 10-Q for the quarter ended March 31, 2004 to reflect changes therein required as a consequence of the adjustments described above.
DESCRIPTION
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GLOSSARY OF TERMS
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
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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."
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| | | | | | Crosstex Energy Services, Ltd.(2) | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Crosstex Energy, Inc. | ||||||||||||||||||||||
| | Four Months Ended April 30, 2000 | | |||||||||||||||||||||
| | Year Ended December 31, 2003(1) (Restated) | Year Ended December 31, 2002(1) (Restated) | Year Ended December 31, 2001 | Eight Months Ended December 31, 2000 | Year Ended December 31, 1999 | ||||||||||||||||||
| | ($ in thousands, except per share data) | ||||||||||||||||||||||
| Statement of Operations Data: | |||||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Midstream | $ | 993,140 | $ | 437,432 | $ | 362,673 | $ | 88,008 | $ | 3,591 | $ | 7,896 | |||||||||||
| Treating | 20,523 | 14,817 | 24,353 | 17,392 | 5,947 | 9,770 | |||||||||||||||||
| Total revenues | 1,013,663 | 452,249 | 387,026 | 105,400 | 9,538 | 17,666 | |||||||||||||||||
| Operating costs and expenses: | |||||||||||||||||||||||
| Midstream purchased gas | 946,412 | 414,244 | 344,755 | 83,672 | 2,746 | 5,154 | |||||||||||||||||
| Treating purchased gas | 7,568 | 5,767 | 18,078 | 14,876 | 4,731 | 8,110 | |||||||||||||||||
| Operating expenses | 17,758 | 11,420 | 7,761 | 1,796 | 544 | 986 | |||||||||||||||||
| General and administrative | 11,593 | 7,663 | 5,583 | 2,010 | 810 | 2,078 | |||||||||||||||||
| Stock based compensation | 5,345 | 41 | — | — | 8,802 | — | |||||||||||||||||
| Impairments | — | 4,175 | 2,873 | — | — | 538 | |||||||||||||||||
| (Profit) loss on energy trading contracts | (1,905 | ) | (1,657 | ) | 3,714 | (1,253 | ) | (638 | ) | (1,764 | ) | ||||||||||||
| Depreciation and amortization | 13,542 | 7,745 | 6,208 | 2,333 | 522 | 1,286 | |||||||||||||||||
| Total operating costs and expenses | 1,000,313 | 449,398 | 388,972 | 103,434 | 17,517 | 16,388 | |||||||||||||||||
| Operating income (loss) | 13,350 | 2,851 | (1,946 | ) | 1,966 | (7,979 | ) | 1,278 | |||||||||||||||
| Other income (expense): | |||||||||||||||||||||||
| Interest expense, net | (3,103 | ) | (2,381 | ) | (2,253 | ) | (530 | ) | (79 | ) | (638 | ) | |||||||||||
| Other income (expense) | 179 | (52 | ) | 174 | 115 | 381 | (138 | ) | |||||||||||||||
| Total other income (expense) | (2,924 | ) | (2,433 | ) | (2,079 | ) | (415 | ) | 302 | (776 | ) | ||||||||||||
| Income (loss) before gain on issuance of units by the partnership, income taxes and interest of non-controlling partners in the partnership's net income | 10,426 | 418 | (4,025 | ) | 1,551 | (7,677 | ) | 502 | |||||||||||||||
| Gain on issuance of partnership units(3) | 18,360 | 11,781 | — | — | — | — | |||||||||||||||||
| Income tax (provision) benefit | (10,157 | ) | (6,871 | ) | 1,294 | (679 | ) | — | — | ||||||||||||||
| Interest of non-controlling partners in the partnership's net income | (5,181 | ) | (99 | ) | — | — | — | — | |||||||||||||||
| Net income (loss) | $ | 13,448 | 5,229 | ($ | 2,731 | ) | $ | 872 | ($ | 7,677 | ) | $ | 502 | ||||||||||
| Net income (loss) per common share—basic(4) | $ | 2.83 | $ | 0.59 | $ | (1.25 | ) | $ | 0.05 | N/A | N/A | ||||||||||||
| Net income (loss) per common share—diluted(4) | $ | 1.10 | $ | 0.46 | $ | (1.25 | ) | $ | 0.05 | N/A | N/A | ||||||||||||
Balance Sheet Data (at period end): | |||||||||||||||||||||||
| Working capital surplus (deficit) | $ | (7,705 | ) | $ | (11,141 | ) | $ | (1,555 | ) | $ | 5,763 | $ | (4,005 | ) | $ | (3,483 | ) | ||||||
| Property and equipment, net | 204,890 | 111,203 | 84,951 | 37,242 | 10,540 | 8,072 | |||||||||||||||||
| Total assets | 370,485 | 241,424 | 171,369 | 202,909 | 45,051 | 36,497 | |||||||||||||||||
| Long-term debt | 60,750 | 22,550 | 60,000 | 22,000 | 7,000 | 5,389 | |||||||||||||||||
| Interest of non-controlling partners in the partnership | 67,157 | 26,815 | — | — | — | — | |||||||||||||||||
| Stockholders' equity | 69,266 | 57,397 | 42,241 | 39,808 | 3,608 | 3,242 | |||||||||||||||||
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Cash Flow Data: | |||||||||||||||||||||||
| Net cash flow provided by (used in): | |||||||||||||||||||||||
| Operating activities | $ | 42,103 | $ | (5,050 | ) | $ | (10,686 | ) | $ | 7,634 | $ | 7,380 | $ | 1,404 | |||||||||
| Investing activities | (110,288 | ) | (33,240 | ) | (52,535 | ) | (25,643 | ) | (2,849 | ) | (1,342 | ) | |||||||||||
| Financing activities | 65,856 | 41,746 | 44,918 | 36,664 | 198 | (857 | ) | ||||||||||||||||
Other Financial Data: | |||||||||||||||||||||||
| Midstream gross margin | $ | 46,728 | $ | 23,188 | $ | 17,918 | $ | 4,336 | $ | 845 | $ | 2,742 | |||||||||||
| Treating gross margin | 12,955 | 9,050 | 6,275 | 2,516 | 1,216 | 1,660 | |||||||||||||||||
| Total gross margin(5) | $ | 59,683 | $ | 32,238 | $ | 24,193 | $ | 6,852 | $ | 2,061 | $ | 4,402 | |||||||||||
Operating Data: | |||||||||||||||||||||||
| Pipeline throughput (MMBtu/d) | 626,000 | 392,000 | 313,000 | 104,000 | 23,000 | 20,000 | |||||||||||||||||
| Natural gas processed (MMBtu/d) | 132,000 | 86,000 | 61,000 | 16,000 | 31,000 | 23,000 | |||||||||||||||||
| Treating volumes (MMBtu/d)(6) | 90,000 | 98,000 | 63,000 | 36,000 | 27,000 | 13,000 | |||||||||||||||||
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.
Restatement
In July 2004, we determined that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. As a result of these errors and as more fully discussed in the Introductory Note to this Amendment No. 1, certain financial and other information contained herein has been restated to reflect adjustments described in Note 2 to the accompanying consolidated financial statements. Please read Note 2 for a discussion of the adjustments.
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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.
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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:
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:
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.
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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 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
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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
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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.
| | Year ended December 31, 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| | Gas Purchased | Gas Sold | ||||||
| Asset or Business | Fixed Amount to Index | Percentage of Index | Fixed Amount to Index | Percentage of Index | ||||
| | (in billions of MMBtus) | |||||||
| Gulf Coast system | 28.5 | 2.5 | 31.1 | — | ||||
| CCNG transmission system | 59.5 | 0.7 | 60.2 | — | ||||
| Gregory gathering system(1) | 52.5 | 2.5 | 45.8 | — | ||||
| Vanderbilt system(1) | 10.2 | 12.4 | 20.0 | — | ||||
| Conroe system(1) | 0.1 | 0.3 | 0.3 | |||||
| Arkoma gathering system | 0.3 | 4.4 | 4.7 | — | ||||
| Mississippi system | 13.5 | 0.5 | 14.0 | |||||
| Producer services(2) | 94.2 | 0.4 | 94.6 | — | ||||
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:
| Period | Volume Hedged (MMBtu per month) | Weighted-Average Price per MMBtu | |||
|---|---|---|---|---|---|
| 1st quarter of 2004 | 90,000 | $ | 5.11 | ||
| 2nd quarter of 2004 | 70,000 | 4.97 | |||
| 3rd quarter of 2004 | 30,000 | 4.85 | |||
| 4th quarter of 2004 | 30,000 | 4.85 | |||
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:
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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.
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.
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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 | 2002 (Restated) | 2001 | |||||||
| | (dollars in millions) | |||||||||
| Midstream revenues | $ | 993.1 | $ | 437.4 | $ | 362.7 | ||||
| Midstream purchased gas | 946.4 | 414.2 | 344.8 | |||||||
| Midstream gross margin | 46.7 | 23.2 | 17.9 | |||||||
| Treating revenues | 20.5 | 14.8 | 24.4 | |||||||
| Treating purchased gas | 7.5 | 5.8 | 18.1 | |||||||
| Treating gross margin | 13.0 | 9.0 | 6.3 | |||||||
| Total gross margin | $ | 59.7 | $ | 32.2 | $ | 24.2 | ||||
| Midstream Volumes (MMBtu/d): | ||||||||||
| Gathering and transportation | 626,000 | 392,000 | 313,000 | |||||||
| Processing | 132,000 | 86,000 | 61,000 | |||||||
| Producer services | 259,000 | 230,000 | 283,000 | |||||||
| Treating Volumes (MMBtu/d) | 90,000 | 98,000 | 63,000 | |||||||
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 $23.2 million (restated) for the year ended December 31, 2002, an increase of $23.5 million, or 101%. 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.
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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 56%. 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 $7.7 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 $1.7 million (restated) for the year ended December 31, 2002, an increase of $0.2 million, or 12%. 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 $0.1 million (restated) 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 $6.9 million (restated) in 2002, an increase of approximately $3.3 million. This increase was primarily due to the increase in the gain on issuance of units of the Partnership and the increase
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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 $5.2 million (restated) for the year ended December 31, 2002, an increase of $8.2 million. This increase in net income was principally the result of the increase of $6.6 million in gains on issuance of units in the Partnership and the increase in gross margin of $27.4 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 $23.2 million (restated) for the year ended December 31, 2002 compared to $17.9 million for the year ended December 31, 2001, an increase of $5.3 million, or 30%. 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 $3.6 million, or 46%. $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 38%. 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
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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 $1.7 million (restated) 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 $5.4 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. This variance is primarily due to the $5.7 million reserve booked in 2001 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 $11.8 million. Accordingly, we recognized an $11.8 million gain in 2002.
Income Taxes. Our income tax expense was $6.9 million (restated) 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
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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 $5.2 million (restated) compared to ($2.7) million for the year ended December 31, 2001, an increase of $7.9 million. Gross margin increased by $8.0 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 $11.8 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.
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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
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to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Liquidity and Capital Resources
Cash Flows. 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 $12.4 million (restated) in 2002. Changes in working capital provided $14.4 million in cash flows from operating activities in 2003 and used $17.5 million (restated) 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
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($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.
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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.
| | Cash Distributions to Us | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | IPO to December 31, 2002(1) | Quarter Ended March 31, 2003 | Quarter Ended June 30, 2003 | Quarter Ended September 30, 2003 | Quarter Ended December 31, 2003 | ||||||||||||
| Crosstex Energy, L.P. distribution per unit | $ | 0.076 | $ | 0.500 | $ | 0.550 | $ | 0.700 | $ | 0.75 | |||||||
| Limited Partner Ownership Interest: | |||||||||||||||||
| 333,000 common units | $ | 25,308 | $ | 166,500 | $ | 183,150 | $ | 233,100 | $ | 249,750 | |||||||
| 4,667,000 subordinated units | 354,692 | 2,333,500 | 2,566,850 | 3,266,900 | 3,500,250 | ||||||||||||
| Total | 380,000 | 2,500,000 | 2,750,000 | 3,500,000 | 3,750,000 | ||||||||||||
| General Partner Ownership Interest: | |||||||||||||||||
| 2.0% general partner interest | 11,322 | 74,490 | 83,078 | 136,686 | 148,719 | ||||||||||||
| Incentive distribution rights | 0 | 0 | 55,824 | 380,112 | 518,495 | ||||||||||||
| Total | 11,322 | 74,490 | 138,902 | 516,798 | 667,214 | ||||||||||||
| Total | $ | 391,322 | $ | 2,574,490 | $ | 2,888,902 | $ | 4,016,798 | $ | 4,417,214 | |||||||
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:
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
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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:
| | Payments due by period | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Contractual Obligations | Total | 2004 | 2005 | 2006 | 2007- 2008 | Thereafter | ||||||||||||
| | (in millions) | |||||||||||||||||
| Long-Term Debt | $ | 60.8 | $ | .1 | $ | .1 | $ | 28.8 | $ | 19.4 | $ | 12.4 | ||||||
| Capital Lease Obligations | — | — | — | — | — | — | ||||||||||||
| Operating Leases | $ | 5.6 | $ | 1.2 | $ | 1.1 | $ | 1.0 | $ | 1.4 | $ | .9 | ||||||
| Unconditional Purchase Obligations | — | — | — | — | — | — | ||||||||||||
| Other Long-Term Obligations | — | — | — | — | — | — | ||||||||||||
| Total Contractual Obligations | $ | 66.4 | $ | 1.3 | $ | 1.2 | $ | 29.8 | $ | 20.8 | $ | 13.3 | ||||||
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.
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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:
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 rankspari 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:
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The bank credit facility also contains covenants requiring us to maintain:
Each of the following will be an event of default under the Partnership's bank credit facility:
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.
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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 leastpari 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.
22
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
23
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/A 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:
24
independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity;
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.
25
Item 8.Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-47 of this Report and are incorporated herein by reference.
Item 9A.Controls And Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, 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, to the extent and in the case described in the following paragraph, our disclosure controls and procedures were not 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.
In July 2004, we determined during the course of internal reviews that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. We identified these errors and promptly brought them to the attention of our audit committee and auditors. As a result of correcting these errors, in this annual report on Form 10-K/A, we have restated our consolidated balance sheets as of December 31, 2002 and 2003, our consolidated statement of operations for the year ended December 31, 2002, our consolidated statements of changes in stockholders' equity for the years ended December 31, 2002 and 2003, our consolidated statement of comprehensive income for the year ended December 31, 2002 and our consolidated statement of cash flows for the year ended December 31, 2002. We have also restated our notes to consolidated financial statements as necessary to reflect the adjustments. These errors resulted from a deficiency in the procedures to reconcile the detail accounts receivable and accounts payable subledgers to the general ledger. Our independent auditors, KPMG LLP, have reviewed these matters and advised our Audit Committee that the deficiency constituted a material weakness as defined in Statements of Auditing Standards No. 60. In light of the discovery of these errors, we have implemented new procedures for reconciling subledgers to the general ledger and disposition and resolution of reconciling items on a timely basis. Management believes that controls are now in place to ensure that similar errors do not occur again.
There have been no changes in our internal controls over financial reporting that occurred during the three months ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
26
Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
| Number | Description | |||
|---|---|---|---|---|
| 3.1* | — | 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) | ||
27
| 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) | ||
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| 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) | ||
| 23.1** | — | Consent of KPMG LLP. | ||
| 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 |
Registrant did not file any Current Reports on Form 8-K during the fourth quarter of 2003.
29
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 19th day of August 2004.
| CROSSTEX ENERGY, INC. | ||||
By: /s/ BARRY E. DAVIS Barry E. Davis, President and Chief Executive Officer | ||||
30
F-1
Report of Independent Registered Public Accounting Firm
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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 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 U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects, the information set forth therein.
As explained in note 3 to the consolidated financial statements, effective January 1, 2001, the Partnership changed its method of accounting for derivatives. Also, as explained in note 3 to the financial statements, effective January 1, 2002, the Company changed its method of amortizing goodwill.
As discussed in note 2 to the accompanying consolidated financial statements, the accompanying balance sheets as of December 31, 2003 and 2002, the consolidated statements of changes in stockholders' equity for the years ended December 31, 2003 and 2002, the consolidated statements of operations, cash flows and comprehensive income for the year ended December 31, 2002, and financial statement schedule I have been restated.
/s/ KPMG LLP
Dallas, Texas,
February 26, 2004 except as to note 2,
which is as of August 9, 2004.
F-2
CROSSTEX ENERGY, INC.
Consolidated Balance Sheets December 31, 2003 and 2002
(In thousands, except share data)
| | December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 (Restated) | 2002 (Restated) | ||||||||
| Assets | ||||||||||
| Current assets: | ||||||||||
| Cash and cash equivalents | $ | 1,479 | $ | 3,808 | ||||||
| Accounts receivable: | ||||||||||
| Trade | 10,238 | 27,049 | ||||||||
| Accrued revenues | 124,517 | 78,500 | ||||||||
| Imbalances | 447 | 79 | ||||||||
| Related party | 617 | — | ||||||||
| Other | 2,628 | 1,037 | ||||||||
| Note receivable | 535 | — | ||||||||
| Fair value of derivative assets | 4,080 | 2,947 | ||||||||
| Prepaid expenses and other | 2,013 | 1,256 | ||||||||
| Total current assets | 146,554 | 114,676 | ||||||||
| Property and equipment: | ||||||||||
| Transmission assets | 99,650 | 50,391 | ||||||||
| Gathering systems | 27,990 | 22,624 | ||||||||
| Gas plants | 88,395 | 40,730 | ||||||||
| Other property and equipment | 3,743 | 2,754 | ||||||||
| Construction in process | 9,863 | 6,935 | ||||||||
| Total property and equipment | 229,641 | 123,434 | ||||||||
| Accumulated depreciation | (24,751 | ) | (12,231 | ) | ||||||
| Total property and equipment, net | 204,890 | 111,203 | ||||||||
| Account receivable from Enron (net of allowance of $6,931 and $5,776 in 2003 and 2002, respectively) | 1,312 | 2,467 | ||||||||
| Fair value of derivative assets | — | 155 | ||||||||
| Intangible assets, net | 5,366 | 5,340 | ||||||||
| Goodwill, net | 6,164 | 6,458 | ||||||||
| Investment in limited partnerships | 2,560 | 346 | ||||||||
| Other assets, net | 3,639 | 778 | ||||||||
| Total assets | $ | 370,485 | $ | 241,423 | ||||||
| Liabilities and Stockholders' Equity | ||||||||||
| Current liabilities: | ||||||||||
| Drafts payable | $ | 10,446 | $ | 27,546 | ||||||
| Accounts payable | 6,325 | 11,461 | ||||||||
| Accrued gas purchases | 119,900 | 74,912 | ||||||||
| Accounts payable-related party | 448 | — | ||||||||
| Preferred dividends payable | 3,471 | 3,021 | ||||||||
| Accrued imbalances payable | 212 | 149 | ||||||||
| Fair value of derivative liabilities | 2,487 | 4,006 | ||||||||
| Current portion of long-term debt | 50 | 50 | ||||||||
| Other current liabilities | 10,920 | 4,672 | ||||||||
| Total current liabilities | 154,259 | 125,817 | ||||||||
| Fair value of derivative liabilities | — | 452 | ||||||||
| Deferred tax liability | 19,103 | 8,443 | ||||||||
| Long-term debt | 60,700 | 22,500 | ||||||||
| Interest of non-controlling partners in the Partnership | 67,157 | 26,815 | ||||||||
| Stockholders' equity: | ||||||||||
| Convertible preferred stock (7,500,000 authorized shares, $.01 par value, 4,123,642 and 4,093,642 issued and outstanding in 2003 and 2002, respectively, $50,740 liquidation value in 2003) | 42 | 42 | ||||||||
| Common stock (4,000,000 shares authorized, $.01 par value, 1,743,032 and 1,882,772 issued and outstanding in 2003 and 2002, respectively) | 19 | 19 | ||||||||
| Additional paid-in capital | 68,934 | 64,913 | ||||||||
| Retained earnings | 7,549 | (2,315 | ) | |||||||
| Treasury stock, at cost (139,740 common shares) | (2,500 | ) | — | |||||||
| Accumulated other comprehensive income | 506 | (528 | ) | |||||||
| Notes receivable from stockholders | (5,284 | ) | (4,735 | ) | ||||||
| Total stockholders' equity | 69,266 | 57,396 | ||||||||
| Total liabilities and stockholders' equity | $ | 370,485 | $ | 241,423 | ||||||
See accompanying notes to consolidated financial statements
F-3
CROSSTEX ENERGY, INC.
Consolidated Statements of Operations
(In thousands, except per share amounts)
| | Years Ended December 31, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | 2001 | ||||||||
| Revenues: | |||||||||||
| Midstream | $ | 993,140 | $ | 437,432 | $ | 362,673 | |||||
| Treating | 20,523 | 14,817 | 24,353 | ||||||||
| Total revenues | 1,013,663 | 452,249 | 387,026 | ||||||||
| Operating costs and expenses: | |||||||||||
| Midstream purchased gas | 946,412 | 414,244 | 344,755 | ||||||||
| Treating purchased gas | 7,568 | 5,767 | 18,078 | ||||||||
| Operating expenses | 17,758 | 11,420 | 7,761 | ||||||||
| General and administrative | 11,593 | 7,663 | 5,583 | ||||||||
| Stock based compensation | 5,345 | 41 | — | ||||||||
| Impairments | — | 4,175 | 2,873 | ||||||||
| (Profit) loss on energy trading activities | (1,905 | ) | (1,657 | ) | 3,714 | ||||||
| Depreciation and amortization | 13,542 | 7,745 | 6,208 | ||||||||
| Total operating costs and expenses | 1,000,313 | 449,398 | 388,972 | ||||||||
| Operating (loss) income | 13,350 | 2,851 | (1,946 | ) | |||||||
| Other income (expense): | |||||||||||
| Interest expense, net | (3,103 | ) | (2,381 | ) | (2,253 | ) | |||||
| Other income (expense) | 179 | (52 | ) | 174 | |||||||
| Total other income (expense) | (2,924 | ) | (2,433 | ) | (2,079 | ) | |||||
| Income before gain on issuance of units by the Partnership, income taxes and interest of non-controlling partners in the Partnership's net income | 10,426 | 418 | (4,025 | ) | |||||||
| Gain on issuance of units of the Partnership | 18,360 | 11,781 | — | ||||||||
| Income tax (provision) benefit | (10,157 | ) | (6,871 | ) | 1,294 | ||||||
| Interest of non-controlling partners in the Partnership's net income | (5,181 | ) | (99 | ) | — | ||||||
| Net income (loss) | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | ||||
| Preferred stock dividends | $ | 3,584 | $ | 3,021 | $ | 1,970 | |||||
| Net income (loss) available to common | $ | 9,864 | $ | 2,208 | $ | (4,701 | ) | ||||
| Basic earnings (loss) per common share | $ | 2.83 | $ | 0.59 | $ | (1.25 | ) | ||||
| Diluted earnings (loss) per common share | $ | 1.10 | $ | 0.46 | $ | (1.25 | ) | ||||
| Weighted-average shares outstanding: | |||||||||||
| Basic | 3,486 | 3,766 | 3,766 | ||||||||
| Diluted | 12,271 | 11,361 | 3,766 | ||||||||
See accompanying notes to consolidated financial statements.
F-4
CROSSTEX ENERGY, INC.
Consolidated Statements of Changes in Stockholders' Equity
Years ended December 31, 2003 (Restated), 2002 (Restated) and 2001
(In thousands, except share data)
| | | | | | | | | Accumulated other Compre- hensive Income | | | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Preferred Stock | Common Stock | | | | | Total Stock- holders' Equity | |||||||||||||||||||||||
| | Additional Paid-In Capital | Treasury Stock | Retained Earnings | Notes Receivable | ||||||||||||||||||||||||||
| | Shares | Amt | Shares | Amt | ||||||||||||||||||||||||||
| Balance, December 31, 2000 | 2,319,375 | $ | 24 | 1,882,772 | $ | 19 | $ | 41,980 | $ | — | $ | 178 | $ | — | $ | (2,393 | ) | $ | 39,808 | |||||||||||
| Issuance of preferred stock | 581,663 | 6 | — | — | 6,934 | — | — | — | (1,920 | ) | 5,020 | |||||||||||||||||||
| Preferred dividends | 192,604 | 2 | — | — | 1,968 | — | (1,970 | ) | — | — | — | |||||||||||||||||||
| Change in notes receivable | — | — | — | — | — | — | — | — | 52 | 52 | ||||||||||||||||||||
| Net loss | — | — | — | — | — | — | (2,731 | ) | — | — | (2,731 | ) | ||||||||||||||||||
| Cumulative adjustment from adoption of accounting standard | — | — | — | — | — | — | — | (654 | ) | — | (654 | ) | ||||||||||||||||||
| Hedging gains or losses reclassified to earnings | — | — | — | — | — | — | — | 654 | — | 654 | ||||||||||||||||||||
| Adjustment in fair value of derivatives | — | — | — | — | — | — | — | 92 | — | 92 | ||||||||||||||||||||
| Balance, December 31, 2001 | 3,093,642 | 32 | 1,882,772 | 19 | 50,882 | — | (4,523 | ) | 92 | (4,261 | ) | 42,241 | ||||||||||||||||||
| Issuance of preferred stock | 1,000,000 | 10 | — | — | 13,990 | — | — | — | — | 14,000 | ||||||||||||||||||||
| Preferred dividends | — | — | — | — | — | — | (3,021 | ) | — | — | (3,021 | ) | ||||||||||||||||||
| Change in notes receivable | — | — | — | — | — | — | — | — | (474 | ) | (474 | ) | ||||||||||||||||||
| Stock based compensation | — | — | — | — | 41 | — | — | — | — | 41 | ||||||||||||||||||||
| Net income (restated) | — | — | — | — | — | — | 5,229 | — | — | 5,229 | ||||||||||||||||||||
| Non-controlling partners' share of other comprehensive income in the Partnership | — | — | — | — | — | — | — | 236 | — | 236 | ||||||||||||||||||||
| Hedging gains or losses reclassified to earnings | — | — | — | — | — | — | — | (116 | ) | — | (116 | ) | ||||||||||||||||||
| Adjustment in fair value of derivatives | — | — | — | — | — | — | — | (740 | ) | — | (740 | ) | ||||||||||||||||||
| Balance, December 31, 2002 (restated) | 4,093,642 | 42 | 1,882,772 | 19 | 64,913 | — | (2,315 | ) | (528 | ) | (4,735 | ) | 57,396 | |||||||||||||||||
| Issuance of preferred stock | 30,000 | — | — | — | 400 | — | — | — | (360 | ) | 40 | |||||||||||||||||||
| Treasury stock purchased | — | — | (139,740 | ) | — | — | (2,500 | ) | — | — | — | (2,500 | ) | |||||||||||||||||
| Non-cash stock based compensation | — | — | — | — | 3,621 | — | — | — | — | 3,621 | ||||||||||||||||||||
| Preferred dividends | — | — | — | — | — | — | (3,584 | ) | — | — | (3,584 | ) | ||||||||||||||||||
| Change in notes receivable | — | — | — | — | — | — | — | — | (189 | ) | (189 | ) | ||||||||||||||||||
| Net income | — | — | — | — | — | — | 13,448 | — | — | 13,448 | ||||||||||||||||||||
| Non-controlling partners' share of other comprehensive income in the Partnership | — | — | — | — | — | — | — | 298 | — | 298 | ||||||||||||||||||||
| Hedging gains or losses reclassified to earnings | — | — | — | — | — | — | — | 1,725 | — | 1,725 | ||||||||||||||||||||
| Adjustment in fair value of derivatives | — | — | — | — | — | — | — | (989 | ) | — | (989 | ) | ||||||||||||||||||
| Balance, year ended December 31, 2003 (restated) | 4,123,642 | $ | 42 | 1,743,032 | $ | 19 | $ | 68,934 | $ | (2,500 | ) | $ | 7,549 | $ | 506 | $ | (5,284 | ) | $ | 69,266 | ||||||||||
See accompanying notes to consolidated financial statements.
F-5
CROSSTEX ENERGY, INC.
Consolidated Statements of Comprehensive Income
December 31, 2003, 2002 and 2001
(In thousands)
| | 2003 | 2002 (Restated) | 2001 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Net income (loss) | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | ||||
| Cumulative adjustment from adoption of accounting standard | — | — | (654 | ) | |||||||
| Non-controlling partners' share of other comprehensive income in the Partnership | 298 | 236 | — | ||||||||
| Hedging gains or losses reclassified to earnings | 1,725 | (116 | ) | 654 | |||||||
| Adjustment in fair value of derivatives | (989 | ) | (740 | ) | 92 | ||||||
| Comprehensive income (loss) | $ | 14,482 | $ | 4,609 | $ | (2,639 | ) | ||||
See accompanying notes to consolidated financial statements
F-6
CROSSTEX ENERGY, INC.
Consolidated Statements of Cash Flows
(In thousands)
| | Years Ended December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | 2001 | |||||||||
| Cash flows from operating activities: | ||||||||||||
| Net income (loss) | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | |||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
| Depreciation and amortization | 13,542 | 7,745 | 6,208 | |||||||||
| Impairments | — | 4,175 | 2,873 | |||||||||
| (Income) loss on investment in affiliated partnerships | (208 | ) | 41 | (35 | ) | |||||||
| Gain on issuance of units of the Partnership | (18,360 | ) | (11,781 | ) | — | |||||||
| Interest of non-controlling partners in the Partnership net income | 5,181 | 99 | — | |||||||||
| Deferred tax | 10,103 | 6,871 | (994 | ) | ||||||||
| Non-cash stock based compensation | 3,967 | 41 | — | |||||||||
| Changes in assets and liabilities: | ||||||||||||
| Accounts receivable and accrued revenues | (31,782 | ) | (47,300 | ) | 47,165 | |||||||
| Prepaid expenses | (1,292 | ) | 239 | (1,814 | ) | |||||||
| Accounts payable, accrued gas purchased, and other accrued liabilities | 40,363 | 31,926 | (65,133 | ) | ||||||||
| Fair value of derivatives | (389 | ) | (4,668 | ) | 4,573 | |||||||
| Other | 7,530 | 2,333 | (798 | ) | ||||||||
| Net cash provided by (used in) operating activities | 42,103 | (5,050 | ) | (10,686 | ) | |||||||
| Cash flows from investing activities: | ||||||||||||
| Additions to property and equipment | (39,003 | ) | (14,545 | ) | (22,685 | ) | ||||||
| Asset purchases | (68,124 | ) | (18,785 | ) | (30,003 | ) | ||||||
| Additions to intangibles and other non-current assets | (1,027 | ) | — | — | ||||||||
| Distributions from (contributions to) affiliated partnerships | (2,134 | ) | 90 | 153 | ||||||||
| Net cash used in investing activities | (110,288 | ) | (33,240 | ) | (52,535 | ) | ||||||
| Cash flows from financing activities: | ||||||||||||
| Proceeds from bank borrowings | 320,100 | 384,050 | 267,131 | |||||||||
| Payments on bank borrowings | (281,900 | ) | (421,500 | ) | (229,150 | ) | ||||||
| Drafts payable | (17,100 | ) | 25,628 | 1,918 | ||||||||
| Distribution to non-controlling partners in the Partnership | (5,408 | ) | — | — | ||||||||
| Deferred dividends paid | (3,134 | ) | — | — | ||||||||
| Debt refinancing and offering costs | (2,200 | ) | — | — | ||||||||
| Net proceeds from issuance of units of the Partnership | 57,958 | 39,568 | — | |||||||||
| Purchase of treasury stock | (2,500 | ) | — | — | ||||||||
| Proceeds from sale of common and preferred stock | 40 | 14,000 | 5,019 | |||||||||
| Net cash provided by (used in) financing activities | 65,856 | 41,746 | 44,918 | |||||||||
| Net increase (decrease) in cash and cash equivalents | (2,329 | ) | 3,456 | (18,303 | ) | |||||||
| Cash and cash equivalents, beginning of period | 3,808 | 352 | 18,655 | |||||||||
| Cash and cash equivalents, end of period | $ | 1,479 | $ | 3,808 | $ | 352 | ||||||
Cash paid for interest | $ | 3,394 | $ | 2,558 | $ | 2,720 | ||||||
| Cash paid for income taxes | — | — | 300 | |||||||||
| Notes receivable from management for stock issuances | — | — | 1,920 | |||||||||
See accompanying notes to consolidated financial statements.
F-7
CROSSTEX ENERGY, INC.
Notes to Consolidated Financial Statements
December 31, 2003 and 2002
(Restated)
(1) Organization and Summary of Significant Agreements:
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.
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
F-8
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.
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) Restatement of Previously Issued Financial Statements
In July 2004, we determined that certain clerical errors had occurred in 2002 accounting that resulted in certain reconciling items not being properly cleared from the Partnership's accounts payable, accounts receivable and accrued gas purchases resulting in a decrease in the Partnership's net income of $1.7 million. Taking into effect the impact of this change on the Company's income taxes, and gain on issuance of units of the Partnership, this resulted in a decrease in net income of $0.4 million for the Company in 2002. As a result of correcting these errors, we have restated our consolidated statement of operations for the year ended December 31, 2002, our consolidated balance sheets as of December 31, 2003 and 2002, our consolidated statement of cash flows for the year ended December 31, 2002, our consolidated statements of changes in stockholders' equity for the years ended December 31, 2003 and 2002, and our consolidated statement of comprehensive income for the year ended December 31, 2002.
The effects of the revisions on our consolidated statement of operations for the year ended December 31, 2002 are summarized in the following table (in thousands, except share data):
| | Previously Reported | As Restated | ||||||
|---|---|---|---|---|---|---|---|---|
| Revenues: | ||||||||
| Midstream | $ | 437,676 | $ | 437,432 | ||||
| Total revenues | 452,493 | 452,249 | ||||||
| Operating costs and expenses: | ||||||||
| Midstream purchased gas | 413,982 | 414,244 | ||||||
| (Profit) loss on energy trading activities | (2,703 | ) | (1,657 | ) | ||||
| Total operating costs and expenses | 448,090 | 449,398 | ||||||
Operating (loss) income | 4,403 | 2,851 | ||||||
Other income (expense): | ||||||||
| Other income (expense) | 56 | (52 | ) | |||||
| Total other income (expense) | (2,325 | ) | (2,433 | ) | ||||
| Gain on issuance of units of the Partnership | 11,054 | 11,781 | ||||||
| Income tax (provision) benefit | (7,451 | ) | (6,871 | ) | ||||
| Net income (loss) | $ | 5,582 | $ | 5,229 | ||||
| Basic earnings (loss) per common share | $ | 0.68 | $ | 0.59 | ||||
| Diluted earning (loss) per common share | $ | 0.49 | $ | 0.46 | ||||
F-9
The effects of the revisions on our consolidated balance sheets as of December 31, 2003 and 2002 are summarized in the following table (in thousands, except share data):
| | Previously Reported | As Restated | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2003 | 2002 | |||||||||||
| Accounts receivable—Trade | 9,491 | 26,302 | 10,238 | 27,049 | |||||||||||
| Total current assets | 145,807 | 113,929 | 146,554 | 114,676 | |||||||||||
| Total property and equipment, net | 204,890 | 111,203 | 204,890 | 111,203 | |||||||||||
| Total assets | 369,738 | 240,676 | 370,485 | 241,423 | |||||||||||
| Accounts payable | 4,064 | 9,200 | 6,325 | 11,461 | |||||||||||
| Accrued gas purchases | 119,756 | 74,768 | 119,900 | 74,912 | |||||||||||
| Total current liabilities | 151,854 | 123,412 | 154,259 | 125,817 | |||||||||||
| Deferred tax liability | 19,683 | 9,023 | 19,103 | 8,443 | |||||||||||
| Long-term debt | 60,700 | 22,500 | 60,700 | 22,500 | |||||||||||
| Interest of non-controlling partners in the Partnership | 67,882 | 27,540 | 67,157 | 26,815 | |||||||||||
Stockholders' equity: | |||||||||||||||
| Convertible preferred stock (7,500,000 authorized shares, $.01 par value, 4,123,642 and 4,093,642 issued and outstanding in 2003 and 2002, respectively, $50,740 liquidation value in 2003) | 42 | 42 | 42 | 42 | |||||||||||
| Common stock (4,000,000 shares authorized, $.01 par value, 1,743,032 and 1,882,772 issued and outstanding in 2003 and 2002, respectively | 19 | 19 | 19 | 19 | |||||||||||
| Additional paid-in capital | 68,934 | 64,913 | 68,934 | 64,913 | |||||||||||
| Retained earnings | 7,902 | (1,962 | ) | 7,549 | (2,315 | ) | |||||||||
| Treasury stock, at cost (139,740 common shares) | (2,500 | ) | — | (2,500 | ) | — | |||||||||
| Accumulated other comprehensive income | 506 | (528 | ) | 506 | (528 | ) | |||||||||
| Notes receivable from stockholders | (5,284 | ) | (4,735 | ) | (5,284 | ) | (4,735 | ) | |||||||
| Total stockholders' equity | $ | 69,619 | $ | 57,749 | $ | 69,266 | $ | 57,396 | |||||||
The effects of the revisions on our consolidated statement of changes in stockholders' equity are a decrease in net income of $0.4 million and a corresponding decrease in stockholders' equity of $0.4 million from retained earnings.
F-10
The effects of the revisions on our consolidated statement of cash flows for the year ended December 31, 2002 are summarized in the following table (in thousands):
| | Previously Reported | As Restated | ||||||
|---|---|---|---|---|---|---|---|---|
| Net income (loss) | $ | 5,582 | $ | 5,229 | ||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||
| Changes in assets and liabilities: | ||||||||
| Accounts receivable and accrued revenue | (46,554 | ) | (47,300 | ) | ||||
| Accounts payable, accrued gas purchases, and other accrued liabilities | 29,521 | 31,926 | ||||||
| Net cash provided by (used in) operating activities | (5,050 | ) | (5,050 | ) | ||||
| Net cash provided by (used in) investing activities | (33,240 | ) | (33,240 | ) | ||||
| Net cash provided by (used in) financing activities | 41,746 | 41,746 | ||||||
There was no net impact on cash flows due to the restatement.
The effects of the revisions on our consolidated statement of comprehensive income for the year ended December 31, 2002 are summarized in the following table (in thousands):
| | Previously Reported | As Restated | ||||||
|---|---|---|---|---|---|---|---|---|
| Net income (loss) | $ | 5,582 | $ | 5,229 | ||||
| Non-controlling partners' share of other comprehensive income in the Partnership | 236 | 236 | ||||||
| Hedging gains or losses reclassified to earnings | (116 | ) | (116 | ) | ||||
| Adjustment in fair value of derivatives | (740 | ) | (740 | ) | ||||
| Comprehensive income (loss) | $ | 4,962 | $ | 4,609 | ||||
The stock based compensation in note 3, the income tax information in note 8, the segment information in note 16 and the quarterly financial data in note 17 have been restated to reflect the impact of the correction of the clerical errors.
(3) Significant Accounting Policies
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 11.
F-11
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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:
| | Useful Lives | |
|---|---|---|
| Transmission assets | 15 years | |
| Gathering systems | 7-15 years | |
| Gas treating, gas processing and carbon dioxide plants | 10-15 years | |
| Other property and equipment | 5 years |
Statement of Financial Accounting Standards ("SFAS") No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, requires long-lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the 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
F-12
regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which would require us to record an impairment of an asset.
Until January 1, 2002, goodwill was amortized 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).
| | Year Ended December 31, 2001 | ||||
|---|---|---|---|---|---|
| Reported net loss | $ | (2,731 | ) | ||
| Goodwill amortization | 390 | ||||
| Pro forma net loss | $ | (2,341 | ) | ||
Pro forma net loss per common share (adjusted for the two-for-one stock split made in conjunction with the Company's January 2004 initial public offering): | |||||
| Basic | $ | (1.15 | ) | ||
| Diluted | $ | (1.15 | ) | ||
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.
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
F-13
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.
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.
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).
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
F-14
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.
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.
F-15
Energy trading contract volumes that were physically settled were as follows (in MMBTUs):
| | Years Ended December 31, | |||||
|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | |||
| Volumes purchased and sold | 94,572,000 | 84,069,000 | 103,331,000 | |||
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.
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.
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
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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.
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):
| | Year Ended December 31, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | 2001 | ||||||||
| Net income (loss), as reported and restated | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | ||||
| Add: Stock-based employee compensation expense included in reported net income, net of tax | 3,474 | 27 | — | ||||||||
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax | (3,636 | ) | (213 | ) | (147 | ) | |||||
| Pro forma net income (loss) | $ | 13,286 | $ | 5,043 | $ | (2,878 | ) | ||||
Pro forma net income (loss) per common share (adjusted for the two-for-one stock split made in conjunction with the Company's January 2004 initial public offering): | |||||||||||
| Basic | $ | 2.78 | $ | 0.54 | $ | (1.29 | ) | ||||
| Diluted | $ | 1.08 | $ | 0.44 | $ | (1.29 | ) | ||||
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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 2003, 2002 and 2001:
| | Crosstex Energy, Inc. | Crosstex Energy, L.P. | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2002 | 2001 | 2003 | 2002 | |||||||||
| Dividend yield | 0 | % | 0 | % | 9.8 | % | 10 | % | |||||
| Expected volatility | 0 | % | 0 | % | 24 | % | 24 | % | |||||
| Risk free interest rate | 4.1 | % | 5.8 | % | 2.65 | % | 2.2 | % | |||||
| Expected life | 3 years | 3 years | 4.3 years | 3 years | |||||||||
| Contractual life | 3 | 3.6 | 10 | 10 | |||||||||
| Weighted average of fair value of options granted | $ | — | $ | — | $ | 2.56 | $ | 1.15 | |||||
| Fair value of $5 options granted* | 1.59 | 1.64 | — | — | |||||||||
| Fair value of $6 options granted* | 0.70 | 0.76 | — | — | |||||||||
| Fair value of $7 options granted* | 0.46 | — | — | — | |||||||||
No Crosstex Energy, Inc. options were granted in 2003.
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.
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
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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.
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(4) Public Offerings of Units by CELP and Certain Provisions of the Partnership Agreement
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):
| Proceeds received: | |||||
| Sale of common units | $ | 46,000 | |||
Use of proceeds: | |||||
| Underwriters' fees | $ | 3,220 | |||
| Professional fees and other offering costs | 2,590 | ||||
| Repayment of debt | 33,000 | ||||
| Distribution to Crosstex Holdings | 2,500 | ||||
| Working capital | 4,690 | ||||
| Total use of proceeds | $ | 46,000 | |||
The Crosstex Energy, L.P. partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. Net income is allocated to the general partner based on incentive distributions earned for the period plus 2% of remaining net income.
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.
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.
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The subordination period will end once the Partnership meets the financial tests in the partnership agreement, but it generally cannot end before December 31, 2007. When the subordination period ends, each remaining subordinated unit will convert into one common unit and the common units will no longer be entitled to arrearages.
If the Partnership meets the applicable financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after December 31, 2005, 25% of the subordinated units will convert to common units. If the Partnership meets these tests for any three consecutive four-quarter periods ending on or after December 31, 2006, an additional 25% of the subordinated units will convert to common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.
In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter commencing with the quarter ending on March 31, 2003. Distributions will generally be made 98% to the common and subordinated 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.
(5) 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
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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):
| Gas plant | $ | 11,837 | |
| Gathering systems | 10,192 | ||
| Transmission assets | 7,158 | ||
| Other property, plant, and equipment | 816 | ||
| $ | 30,003 | ||
On October 11, 2001, CES entered into a purchase and sale agreement with various individuals to acquire the common stock of Millennium Gas Services, Inc. ("Millennium") for a total of $2,124,000 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
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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):
| Purchase price to DEFS | $ | 66,356 | ||
| Direct acquisition costs | 1,768 | |||
| Total purchase price | $ | 68,124 | ||
Current assets acquired | $ | 426 | ||
| Liabilities assumed | (813 | ) | ||
| Property, plant and equipment | 67,589 | |||
| Intangible assets | 922 | |||
| Total purchase price | $ | 68,124 | ||
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):
| | Year Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | |||||
| Revenue | $ | 1,119,985 | $ | 589,504 | |||
| Net income | $ | 13,889 | $ | 6,513 | |||
| Net income (loss) per common share— | |||||||
| Basic | $ | 2.96 | $ | 0.93 | |||
| Diluted | $ | 1.13 | $ | 0.57 | |||
(6) 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.
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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):
| Revenues | $ | 203 | ||
| Costs and expenses | (248 | ) | ||
| Net loss | $ | (45 | ) | |
Current assets | $ | 322 | ||
| Non-current assets | 4,513 | |||
| Current liabilities | 809 | |||
| Non-current liabilities | — | |||
| Partners' equity | 4,026 | |||
(7) 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:
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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 million 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 rankspari 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:
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The credit facility contains the following covenants requiring the Partnership to maintain:
Each of the following will be an event of default under the bank credit facility:
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.
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The notes represent senior secured obligations of our operating partnership and will rank at leastpari 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%.
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As of December 31, 2003 and 2002, long-term debt consisted of the following (in thousands):
| | 2003 | 2002 | ||||||
|---|---|---|---|---|---|---|---|---|
| Acquisition credit facility, interest based at prime plus an applicable margin, interest rate at December 31, 2002 was 4.88% | $ | — | $ | 1,750 | ||||
| Acquisition credit facility, interest based on LIBOR plus an applicable margin, interest rates at December 31, 2003 and 2002 were 2.92% and 3.95%, respectively | 20,000 | 20,000 | ||||||
| Senior secured notes, weighted average interest rate of 6.93% | 40,000 | — | ||||||
| Note payable to Florida Gas Transmission Company | 750 | 800 | ||||||
| 60,750 | 22,550 | |||||||
| Less current portion | (50 | ) | (50 | ) | ||||
| Debt classified as long-term | $ | 60,700 | $ | 22,500 | ||||
Maturities for the long-term debt as of December 31, 2003 are as follows (in thousands):
| 2004 | $ | 50 | |
| 2005 | 50 | ||
| 2006 | 28,874 | ||
| 2007 | 10,012 | ||
| 2008 | 9,412 | ||
| Thereafter | 12,352 |
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.
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(8) 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).
| | 2003 | 2002 (Restated) | 2001 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Current tax provision (benefit) | $ | 54 | $ | — | $ | (300 | ) | |||
| Deferred tax provision (benefit) | 10,103 | 6,871 | (994 | ) | ||||||
| $ | 10,157 | $ | 6,871 | $ | (1,294 | ) | ||||
A reconciliation of the provision for income taxes is as follows (in thousands):
| | 2003 | 2002 (Restated) | 2001 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Federal income tax (benefit) at statutory rate | $ | 8,262 | $ | 4,235 | $ | (1,409 | ) | |||
| Tax basis adjustment in Partnership related to issuance of common units | 1,895 | 2,620 | — | |||||||
| Non-deductible expenses (primarily goodwill amortization) | — | 16 | 162 | |||||||
| Other | — | — | (47 | ) | ||||||
| Tax provision (benefit) | $ | 10,157 | $ | 6,871 | $ | (1,294 | ) | |||
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The principal components of the Company's net deferred tax liability are as follows (in thousands):
| | 2003 (Restated) | 2002 (Restated) | ||||||
|---|---|---|---|---|---|---|---|---|
| Deferred income tax assets: | ||||||||
| Net operating loss carryforward | $ | 3,742 | $ | 3,804 | ||||
| Enron reserve | 2,386 | 1,981 | ||||||
| Investment in the Partnership | 4,179 | 2,339 | ||||||
| Other comprehensive income | — | 284 | ||||||
| 10,307 | 8,408 | |||||||
| Less: valuation allowance | (4,179 | ) | (2,339 | ) | ||||
| 6,128 | 6,069 | |||||||
Deferred income tax liabilities: | ||||||||
| Property, plant, equipment, and intangible assets | (24,913 | ) | (14,177 | ) | ||||
| Other comprehensive income | (273 | ) | — | |||||
| Other | (45 | ) | (335 | ) | ||||
| (25,231 | ) | (14,512 | ) | |||||
| Net deferred tax liability | $ | (19,103 | ) | $ | (8,443 | ) | ||
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At December 31, 2003, the Company had a net operating loss carryforward of approximately $8.4 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.
(9) 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.
(10) Employee Incentive Plans
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.
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.
F-31
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.
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:
| | December 31, 2003 | December 31, 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| | Number of units | Weighted average exercise price | Number of units | Weighted average exercise price | |||||||
| Outstanding, beginning of period | 175,000 | $ | 20.00 | — | — | ||||||
| Granted | 147,386 | $ | 21.22 | 175,000 | $ | 20.00 | |||||
| Exercised | — | — | — | — | |||||||
| Forfeited | (750 | ) | $ | (20.00 | ) | — | — | ||||
| Outstanding, end of period | 321,636 | $ | 20.56 | 175,000 | $ | 20.00 | |||||
| Options exercisable at end of period | 71,667 | $ | 20.00 | — | |||||||
| Weighted average fair value of options granted | $ | 2.56 | $ | 1.15 | |||||||
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.
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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):
| | December 31, 2003 | December 31, 2002 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | ||||||
| Outstanding, beginning of period | 1,040,500 | $ | 5.39 | 681,000 | $ | 5.16 | ||||
| Granted | — | — | 372,500 | 5.95 | ||||||
| Cancelled | (176,110 | ) | — | — | — | |||||
| Forfeited | (2,000 | ) | 6.00 | (13,000 | ) | 6.00 | ||||
| Outstanding, end of period | 862,390 | 5.42 | 1,040,500 | 5.39 | ||||||
| Options, exercisable at period end | 711,213 | 5.29 | 577,006 | 5.18 | ||||||
Fair value of $5 options granted | N/A | 1.59 | ||||||||
| Fair value of $6 options granted | N/A | 0.70 | ||||||||
| Fair value of $7 options granted | N/A | 0.46 | ||||||||
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
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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.
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):
| | Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | ||||
| Basic earnings: | |||||||
| Weighted-average common shares outstanding | 3,486 | 3,766 | 3,766 | ||||
| Dilutive earnings per unit: | |||||||
| Weighted-average common shares outstanding | 3,486 | 3,766 | 3,766 | ||||
| Dilutive effect of exercise of options outstanding | 573 | 235 | — | ||||
| Dilutive effect of preferred stock conversion to common shares | 8,212 | 7,360 | — | ||||
| Dilutive common shares | 12,271 | 11,361 | 3,766 | ||||
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.
(11) 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
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necessarily indicative of the amount the Company could realize upon the sale or refinancing of such financial instruments (in thousands).
| | 2003 | 2002 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||
| | (Restated) | (Restated) | ||||||||||
| Cash and cash equivalents | $ | 1,479 | $ | 1,479 | $ | 3,808 | $ | 3,808 | ||||
| Trade accounts receivable and accrued revenues | 134,755 | 134,755 | 105,549 | 105,549 | ||||||||
| Fair value of derivative assets | 4,080 | 4,080 | 3,102 | 3,102 | ||||||||
| Account receivable from Enron | 1,312 | 1,312 | 2,468 | 2,468 | ||||||||
| Accounts payable, drafts payable and accrued gas purchases | 136,671 | 136,671 | 113,919 | 113,919 | ||||||||
| Long-term debt | 60,750 | 60,750 | 22,550 | 22,550 | ||||||||
| Fair value of derivative liabilities | 2,487 | 2,487 | 4,458 | 4,458 | ||||||||
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 12).
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.
(12) 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.
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The fair value of derivative assets and liabilities, excluding the interest rate swap, are as follows (in thousands):
| | December 31 | ||||||
|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | |||||
| Fair value of derivative assets—current | $ | 4,080 | $ | 2,947 | |||
| Fair value of derivative assets—long term | — | 155 | |||||
| Fair value of derivative liabilities—current | (2,278 | ) | (4,006 | ) | |||
| Fair value of derivative liabilities—long term | — | (271 | ) | ||||
| Net fair value of derivatives | $ | 1,802 | $ | (1,175 | ) | ||
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
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hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings.
| December 31, 2003 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Transaction type | Total volume | Pricing terms | Remaining term of contracts | Fair value (in thousands) | |||||||
| Cash Flow Hedge: | |||||||||||
| Natural gas swaps Cash flow hedge | (2,630,000 | ) | Fixed prices ranging from $4.01 to $6.545 settling against the various Inside FERC Index prices | January-December 2004 | $ | (563 | ) | ||||
| Natural gas swaps Cash flow hedge | 8,314,000 | January-December 2004 | 2,391 | ||||||||
| Total natural gas swaps Cash flow hedge | $ | 1,828 | |||||||||
Producer Services: | |||||||||||
| Marketing trading financial swaps | 910,000 | Fixed prices ranging from $3.14 to $6.24 settling against the various Inside FERC Index prices | January-December 2004 | $ | 284 | ||||||
| Marketing trading financial swaps | (723,000 | ) | January-December 2004 | (522 | ) | ||||||
| Total marketing trading financial swaps | $ | (238 | ) | ||||||||
Physical offset to marketing trading transactions | (910,000 | ) | Fixed prices ranging from $3.59 to $6.155 settling against the various Inside FERC Index prices | January-December 2004 | $ | (282 | ) | ||||
| Physical offset to marketing trading transactions | 723,000 | January-December 2004 | 494 | ||||||||
| Total physical offset to marketing trading transactions swaps | $ | 212 | |||||||||
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):
| | Maturity periods | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | Less than one year | One to two years | Two to three years | Total fair value | ||||||
| December 31, 2003 | $ | (26 | ) | — | — | (26 | ) | |||
| December 31, 2002 | $ | (99 | ) | (81 | ) | — | (180 | ) | ||
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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.
(13) 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,
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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:
Crosstex Denton County Gathering J.V.
(14) Commitments and Contingencies
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):
| 2004 | $ | 1,228 | |
| 2005 | 1,091 | ||
| 2006 | 960 | ||
| 2007 | 811 | ||
| 2008 | 684 | ||
| Thereafter | 852 | ||
| $ | 5,626 | ||
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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.
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.
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.
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
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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.
(15) Capital 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).
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 19,000,000 shares.
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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).
(16) 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.
F-42
Summarized financial information concerning the Company's reportable segments is shown in the following table. There are no other significant non-cash items.
| | Midstream | Treating | Totals | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| | (In thousands) | ||||||||||
| Year ended December 31, 2003 (restated): | |||||||||||
| Sales to external customers | $ | 993,140 | $ | 20,523 | $ | 1,013,663 | |||||
| Intersegment sales | 6,893 | (6,893 | ) | — | |||||||
| Interest expense | 3,040 | 63 | 3,103 | ||||||||
| Stock based compensation | 4,276 | 1,069 | 5,345 | ||||||||
| Depreciation and amortization | 10,600 | 2,942 | 13,542 | ||||||||
| Segment profit | 8,900 | 1,526 | 10,426 | ||||||||
| Segment assets (restated) | 327,186 | 43,299 | 370,485 | ||||||||
| Capital expenditures | 28,728 | 10,275 | 39,003 | ||||||||
| Year ended December 31, 2002 (restated): | |||||||||||
| Sales to external customers (restated) | $ | 437,432 | $ | 14,817 | $ | 452,249 | |||||
| Intersegment sales | 4,073 | (4,073 | ) | — | |||||||
| Interest expense | 2,039 | 342 | 2,381 | ||||||||
| Impairments | — | 4,175 | 4,175 | ||||||||
| Depreciation and amortization | 5,738 | 2,007 | 7,745 | ||||||||
| Segment profit (loss) (restated) | 1,474 | (1,055 | ) | 419 | |||||||
| Segment assets (restated) | 206,393 | 35,031 | 241,424 | ||||||||
| Capital expenditures | 11,154 | 3,391 | 14,545 | ||||||||
| Year ended December 31, 2001: | |||||||||||
| Sales to external customers | $ | 362,673 | $ | 24,353 | $ | 387,026 | |||||
| Intersegment sales | 10,633 | (10,633 | ) | — | |||||||
| Interest expense | 1,840 | 413 | 2,253 | ||||||||
| Impairments | 2,873 | — | 2,873 | ||||||||
| Depreciation and amortization | 4,611 | 1,597 | 6,208 | ||||||||
| Segment profit (loss) | (4,714 | ) | 689 | (4,025 | ) | ||||||
| Segment assets | 139,129 | 32,240 | 171,369 | ||||||||
| Capital expenditures | 6,484 | 16,201 | 22,685 | ||||||||
(17) Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data is presented below.
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Previously Reported:
| | First | Second | Third | Fourth | Total | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | (In thousands, except per share amounts) | |||||||||||||||
| 2003: | ||||||||||||||||
| Revenues | $ | 250,570 | $ | 229,252 | $ | 283,198 | $ | 250,643 | $ | 1,013,663 | ||||||
| Operating income | 605 | 3,631 | 4,047 | 5,067 | 13,350 | |||||||||||
| Net income | 30 | 1,091 | 11,376 | (2) | 951 | 13,448 | ||||||||||
| Basic earnings per common share | (0.25 | ) | 0.05 | 3.01 | 0.02 | 2.83 | ||||||||||
| Diluted earnings per common share | (0.25 | ) | 0.05 | 0.92 | 0.02 | 1.10 | ||||||||||
| 2002: | ||||||||||||||||
| Revenues | $ | 80,993 | $ | 126,480 | $ | 114,611 | $ | 130,409 | $ | 452,493 | ||||||
| Operating income(1) | 4,681 | 5,468 | 6,182 | 5,934 | 22,265 | |||||||||||
| Net income (loss) | (119 | )(3) | 189 | 1,028 | 4,484 | (4) | 5,582 | |||||||||
| Basic earnings per common share | (0.19 | ) | (0.13 | ) | 0.04 | 0.96 | 0.68 | |||||||||
| Diluted earnings per common share | (0.19 | ) | (0.13 | ) | 0.04 | 0.37 | 0.49 | |||||||||
As Restated(5):
| | First | Second | Third | Fourth | Total | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | (In thousands, except per share amounts) | |||||||||||||||
| 2003: | ||||||||||||||||
| Revenues | $ | 250,570 | $ | 229,252 | $ | 283,198 | $ | 250,643 | $ | 1,013,663 | ||||||
| Operating income | 605 | 3,631 | 4,047 | 5,067 | 13,350 | |||||||||||
| Net income | 30 | 1,091 | 11,376 | (2) | 951 | 13,448 | ||||||||||
| Basic earnings per common share | (0.25 | ) | 0.05 | 3.01 | 0.02 | 2.83 | ||||||||||
| Diluted earnings per common share | (0.25 | ) | 0.05 | 0.92 | 0.02 | 1.10 | ||||||||||
| 2002: | ||||||||||||||||
| Revenues | $ | 80,811 | $ | 126,418 | $ | 114,611 | $ | 130,409 | $ | 452,249 | ||||||
| Operating income (loss) | 137 | (26 | ) | 2,068 | 672 | 2,851 | ||||||||||
| Net income (loss) | (362 | )(3) | (599 | ) | 1,028 | 5,162 | (4) | 5,229 | ||||||||
| Basic earnings per common share | (0.29 | ) | (0.45 | ) | 0.04 | 1.29 | 0.59 | |||||||||
| Diluted earnings per common share | (0.29 | ) | (0.45 | ) | 0.04 | 0.47 | 0.46 | |||||||||
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F-45
SCHEDULE I
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED BALANCE SHEETS
(In thousands)
| | December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| | 2003 (Restated) | 2002 (Restated) | ||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1,313 | $ | 2,500 | ||||
| Federal income tax refund receivable | — | 400 | ||||||
| Prepaid expenses and other | 75 | — | ||||||
| Total current assets | 1,388 | 2,900 | ||||||
| Investment in the Partnership | 88,748 | 62,311 | ||||||
| Investment in subsidiary | 7,459 | 8,488 | ||||||
| Other non-current assets | 465 | — | ||||||
| Total assets | $ | 98,060 | $ | 73,699 | ||||
Liabilities and Stockholders' Equity | ||||||||
| Current liabilities: | ||||||||
| Accrued taxes payable | $ | — | $ | — | ||||
| Preferred dividend payable | 3,471 | 3,021 | ||||||
| Payable to the Partnership | 886 | 104 | ||||||
| Other accrued liabilities | 50 | — | ||||||
| Total current liabilities | 4,407 | 3,125 | ||||||
| Deferred tax liability | 19,103 | 8,443 | ||||||
| Stockholders' equity: | ||||||||
| Convertible preferred stock | 42 | 42 | ||||||
| Common stock | 19 | 19 | ||||||
| Additional paid-in capital | 68,934 | 64,913 | ||||||
| Retained earnings | 7,549 | (2,315 | ) | |||||
| Treasury stock, at cost | (2,500 | ) | — | |||||
| Accumulated other comprehensive income | 506 | (528 | ) | |||||
| Total stockholders' equity | 74,550 | 62,131 | ||||||
| Total liabilities and stockholders' equity | $ | 98,060 | $ | 73,699 | ||||
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
F-46
Schedule I (continued)
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
| | Years Ended December 31, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | 2001 | ||||||||
| Operating income and expenses: | |||||||||||
| Income (loss) from investment in the Partnership | $ | 10,045 | $ | 245 | $ | (4,025 | ) | ||||
| (Loss) from investment in subsidiary | (1,252 | ) | (11 | ) | — | ||||||
| General and administrative | (3,542 | ) | (150 | ) | — | ||||||
| Operating income (loss) | 5,251 | 84 | (4,025 | ) | |||||||
| Other income (expense): | |||||||||||
| Interest income | (6 | ) | 335 | — | |||||||
| Other expense | — | (100 | ) | — | |||||||
| Gain on issuance of units in the Partnership | 18,360 | 11,781 | — | ||||||||
| Income tax provision benefit (expense) | (10,157 | ) | (6,871 | ) | 1,294 | ||||||
| Total other income and expense | 8,197 | 5,145 | 1,294 | ||||||||
| Net income (loss) | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | ||||
Earnings (loss) per share: | |||||||||||
| Basic | $ | 2.83 | $ | 0.59 | $ | (1.25 | ) | ||||
| Diluted | $ | 1.10 | $ | 0.46 | $ | (1.25 | ) | ||||
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
F-47
Schedule I (continued)
CROSSTEX ENERGY, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOW
(In thousands)
| | Years Ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 (Restated) | 2001 | ||||||||||
| Cash flows from operating activities: | |||||||||||||
| Net income (loss) | $ | 13,448 | $ | 5,229 | $ | (2,731 | ) | ||||||
| Adjustments to reconcile net income (loss) to net cash flow provided by (used in) operating activities: | |||||||||||||
| (Income) loss from investment in the Partnership | (10,045 | ) | (245 | ) | 4,025 | ||||||||
| (Income) loss from investment in subsidiary | 1,252 | 11 | — | ||||||||||
| Deferred taxes | 10,103 | 6,871 | (994 | ) | |||||||||
| Stock-based compensation | — | 41 | — | ||||||||||
| Gain on issuance of units in the Partnership | (18,360 | ) | (11,781 | ) | — | ||||||||
| Changes in assets and liabilities: | |||||||||||||
| Accounts receivable | 400 | — | (400 | ) | |||||||||
| Prepaid expenses and other | (539 | ) | 299 | (198 | ) | ||||||||
| Accounts payable and other accrued liabilities | 780 | 48 | (200 | ) | |||||||||
| Net cash provided by (used in) operating activities | (2,961 | ) | 473 | (498 | ) | ||||||||
| Cash flows from investing activities: | |||||||||||||
| Investment in the Partnership | (1,263 | ) | (14,000 | ) | (4,964 | ) | |||||||
| Distributons from the Partnership | 9,872 | 2,500 | 442 | ||||||||||
| Investment in subsidiary | 137 | — | — | ||||||||||
| Net cash provided by (used in) investing activities | 8,746 | (11,500 | ) | (4,522 | ) | ||||||||
| Cash flows from financing activities: | |||||||||||||
| Issuance of preferred stock | 40 | 14,000 | 5,020 | ||||||||||
| Increase in shareholder note receivables | — | (473 | ) | — | |||||||||
| Dividends due to shareholders | (3,134 | ) | — | — | |||||||||
| Redemptions of stock options for cash | (1,378 | ) | — | — | |||||||||
| Purchase of treasury stock | (2,500 | ) | — | — | |||||||||
| Net cash provided by (used in) financing activities | (6,972 | ) | 13,527 | 5,020 | |||||||||
| Net increase (decrease) in cash | (1,187 | ) | 2,500 | — | |||||||||
| Cash, beginning of year | 2,500 | — | — | ||||||||||
| Cash, end of year | $ | 1,313 | $ | 2,500 | $ | — | |||||||
See "Notes to Consolidated Financial Statements" of Crosstex Energy, Inc. included in this report.
F-48
SCHEDULE II
CROSSTEX ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
| | | Additions | | | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions | Balance at End of Period | ||||||||
| Year Ended December 31, 2003: | |||||||||||||
| For doubtful receivables classified as non-current assets | $ | 5,776 | 1,155 | — | — | $ | 6,931 | ||||||
| Year Ended December 31, 2002: | |||||||||||||
| For doubtful receivables classified as non-current assets | $ | 5,776 | — | — | — | $ | 5,776 | ||||||
| Year Ended December 31, 2001: | |||||||||||||
| For doubtful receivables classified as non-current assets | $ | — | 5,776 | (a) | — | — | $ | 5,776 | |||||
F-49
