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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS
FILE PURSUANT TO RULE 424(B)(4)
REGISTRATION NO. 333-97779
PROSPECTUS
2,000,000 Common Units
Crosstex Energy, L.P.
Representing Limited Partner Interests
We are offering 2,000,000 common units representing limited partner interests. This is the initial public offering of our common units. Holders of common units are entitled to receive distributions of available cash of $0.50 per quarter, or $2.00 per unit on an annualized basis, before any distributions are paid on our subordinated units, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. Our common units have been approved for quotation on the Nasdaq National Market under the symbol "XTEX."
Investing in our common units involves risk.
See "Risk Factors" beginning on page 15.
These risks include the following:
PRICE $20.00 PER COMMON UNIT
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Per Common Unit |
Total |
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| Initial public offering price | $ | 20.00 | $ | 40,000,000 | ||
| Underwriting discount | $ | 1.40 | $ | 2,800,000 | ||
| Proceeds, before expenses, to Crosstex Energy, L.P. | $ | 18.60 | $ | 37,200,000 | ||
We have granted the underwriters a 30-day option to purchase up to an additional 300,000 common units to cover over-allotments. The underwriters expect to deliver the common units to purchasers on or about December 17, 2002.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
A.G. Edwards & Sons, Inc.
Raymond James
RBC Capital Markets
Prospectus dated December 11, 2002
[Map showing location of gathering and transmission
systems and processing and treating facilities]
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The summary highlights selected information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements. The information presented in this prospectus assumes that the underwriters' over-allotment option is not exercised. You should read "Summary of Risk Factors" beginning on page 2 and "Risk Factors" beginning on page 15 for more information about important factors that you should consider before buying common units. We have included a "Glossary of Terms" as Appendix C that defines many of the terms we use in this prospectus.
References in this prospectus to "Crosstex Energy, L.P.," "we," "ours," "us," or like terms when used in the present tense or prospectively refer to Crosstex Energy, L.P. and its operating subsidiaries. Crosstex Energy, L.P. is the issuer of securities in this offering. References to "our predecessor," "we," "ours," "us," or like terms when used in a historical context refer to Crosstex Energy Services, Ltd. Substantially all of the assets of Crosstex Energy Services, Ltd. will be transferred to us at the closing of the offering.
We are a rapidly growing independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas. We connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities to ensure that it meets pipeline quality specifications, process natural gas for the removal of natural gas liquids, or NGLs, transport natural gas and ultimately provide an aggregated supply of natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generate gross margins based on the difference between the purchase and resale prices. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee.
We have grown rapidly since the inception of our various predecessors in 1992 through a combination of acquisitions and the construction of new assets. Our income before income taxes plus depreciation and amortization expense and interest expense, which we refer to as EBITDA, has increased from $0.5 million in 1997 to $4.4 million in 2001. Our EBITDA was $9.9 million for the nine months ended September 30, 2002. Our net loss was $3.9 million for the year ended December 31, 2001, and net income was $1.5 million for the nine months ended September 30, 2002. Net income and EBITDA for 2001 and the nine months ended September 30, 2002 have been reduced by non-cash impairment charges of $2.9 million and $3.2 million, respectively.
We have two operating divisions, the Midstream division, which consists of our natural gas gathering, transmission, processing, marketing and producer services operations, and the Treating division, which provides natural gas treating for the removal of carbon dioxide and other contaminants.
Midstream Division
Our primary Midstream assets are four major systems along the Texas Gulf Coast and one in eastern Oklahoma, which in the aggregate consist of approximately 1,500 miles of gathering and transmission pipelines, and a natural gas processing plant connected to one of these gathering systems. For the nine months ended September 30, 2002, we gathered and transported approximately 368,681 Mcf/d of natural gas.
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Texas to Fort Bend County near Houston, Texas. Our Gulf Coast system had an average throughput of approximately 101,021 Mcf/d for the nine months ended September 30, 2002.
In our producer services operations, we purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 80 independent producers. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.
Treating Division
Our treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that the natural gas meets pipeline quality specifications. As of September 30, 2002, we owned 49 mobile, skid-mounted treating plants of various sizes, 23 of which were operated by our personnel, six of which were operated by producers, one of which was operated by a joint venture partner and 19 of which were held in inventory.
An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of common units. Those risks are described under the caption "Risk Factors" and include:
Risks Inherent in Our Business
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Risks Inherent in an Investment in Us
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Tax Risks to Our Unitholders
We believe that we are well positioned to compete in the natural gas gathering, transmission, treating, processing and producer services businesses. Our competitive strengths include:
Our treating operations, with 19 treating plants of varying sizes available in inventory, provides us with an advantageous position to compete for new treating business in the Texas Gulf Coast because natural gas produced from certain deeper formations in the Texas Gulf Coast is high in carbon dioxide. We believe our inventory of available treating plants gives us a competitive advantage for new treating business since we can often have a plant in service quicker than our competitors.
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Our strategy is to increase distributable cash flow per unit by improving the profitability of our existing systems through increasing volumes and reducing costs, focusing on accretive acquisitions and pursuing system construction and expansion opportunities. Key elements of our strategy include the following:
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PARTNERSHIP STRUCTURE AND MANAGEMENT
Our operations will be conducted through, and our operating assets will be owned by, our operating partnership, Crosstex Energy Services, L.P., and its subsidiaries. Our general partner, Crosstex Energy GP, L.P., has sole responsibility for conducting our business and for managing our operations. The senior executives who currently manage our business will continue to manage and operate the business as the senior executives of Crosstex Energy GP, LLC, the general partner of our general partner. Our general partner will not receive any management fee or other compensation in connection with its management of our business but will be entitled to reimbursement for all direct and indirect expenses incurred on our behalf. Upon completion of this offering and the related transactions:
We are using a limited partnership, Crosstex Energy GP, L.P., as our general partner instead of Crosstex Energy Holdings Inc. primarily to limit the liability of Crosstex Energy Holdings Inc. and its institutional holders. Crosstex Energy Services GP, LLC is inserted between us and our operating partnership to serve as the general partner of the operating partnership. In the event that our operating partnership ever issues public debt securities, having the operating partnership and all subsidiary guarantors 100% owned by us will allow the use of condensed financial information for the operating partnership and guarantors instead of separate financial statements. We have no current plans for our operating partnership to issue public debt.
Our principal executive offices are located at 2501 Cedar Springs, Suite 600, Dallas, Texas 75201, and our phone number is (214) 953-9500.
The chart on the following page depicts the organization and ownership of us and our operating partnership after giving effect to the offering and the related formation transactions.
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| Common units offered to the public | 2,000,000 common units. | |||
2,300,000 common units if the underwriters exercise their over-allotment option in full. |
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Units outstanding after this offering |
2,333,000 common units, representing a 32.7% limited partner interest in Crosstex Energy, L.P., and 4,667,000 subordinated units, representing a 65.3% limited partner interest in Crosstex Energy, L.P. Approximately 14.3% of the common units and all of the subordinated units will be owned by affiliates of our general partner. |
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Cash distributions |
We intend to make minimum quarterly distributions of $0.50 per common unit to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. In general, we will pay any cash distributions we make each quarter in the following manner: |
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first, 98% to the common units and 2% to the general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters; and |
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second, 98% to the subordinated units and 2% to the general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50. |
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If cash distributions exceed $0.50 per unit in a quarter, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." Please read "Cash Distribution Policy—Incentive Distribution Rights." |
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We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner in its sole discretion. These reserve funds are meant to provide for the proper conduct of our business including funds needed to provide for our operations as well as to comply with applicable debt instruments. As we cannot estimate the size of these reserves for any given quarter at this time, we cannot assure you that, after the establishment of reserves, we will have cash on hand for distribution to our unitholders. We refer to this cash available for distribution as "available cash," and we define its meaning in our partnership agreement. Please read "Cash Distribution Policy—Distributions of Available Cash" for a description of available cash. The amount of available cash may be greater than or less than the minimum quarterly distribution. |
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We believe, based on the forecast included in Appendix E and the assumptions described therein, that we will have sufficient cash from operations to enable us to make the minimum quarterly distribution of $0.50 on all of the common units and the subordinated units for each quarter through September 30, 2003. The amount of pro forma cash available for distribution generated during 2001 and the first nine months of 2002 would have been sufficient to allow us to pay the minimum quarterly distribution on all of the common units and 5.5% and 78.7%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. Please read "Cash Available for Distribution." |
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Subordination period |
The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before December 31, 2007. |
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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. Please read "Cash Distribution Policy—Subordination Period." |
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Early conversion of subordinated units |
If we meet 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 into common units. If we meet 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 into 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. |
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Issuance of additional units |
In general, while any subordinated units remain outstanding, we may not issue more than 1,166,500 additional common units, or 50% of the common units outstanding immediately after this offering, without obtaining unitholder approval. We may, however, issue an unlimited number of common units for acquisitions, capital improvements or debt repayments that increase cash flow from operations per unit on a pro forma basis. |
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Voting rights |
Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or the directors of its general partner on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Because affiliates of our general partner will own 71.4% of the outstanding units upon completion of the offering, you will not be able to remove the general partner without its consent. |
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Limited call right |
If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own 71.4% of the common units. |
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Estimated ratio of taxable income to distributions |
We estimate that if you own the common units you purchase in this offering through December 31, 2005, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of taxable income to distributions" for the basis of this estimate. |
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Exchange listing |
Our common units have been approved for quotation on the Nasdaq National Market under the symbol "XTEX." |
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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following table sets forth summary historical financial and operating data of our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated and the summary pro forma financial and operating data of Crosstex Energy, L.P. as of and for the year ended December 31, 2001 and the nine months ended September 30, 2002. The summary historical financial data for the years ended December 31, 1999 and 2001 and for the four months ended April 30, 2000 and for the eight months ended December 31, 2000 are derived from the audited financial statements of Crosstex Energy Services, Ltd. and its predecessor. The summary historical financial data for the nine months ended September 30, 2001 and 2002 are derived from the unaudited financial statements of Crosstex Energy Services, Ltd. and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. As described in our historical financial statements, 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 audited 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, the summary historical financial and operating data of Crosstex Energy Services, Ltd. include the results of operations of the Arkoma system beginning in September 2000, the Gulf Coast system beginning in September 2000 and the CCNG system, which includes the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, beginning in May 2001.
The summary pro forma financial and operating data of Crosstex Energy, L.P. reflect the consolidated historical operating results of Crosstex Energy Services, Ltd., as adjusted for the offering and the related transactions. The summary pro forma financial data are derived from the unaudited pro forma financial statements. The pro forma balance sheet assumes that the offering and related transactions occurred on September 30, 2002. The pro forma statements of operations assume that the offering and related transactions occurred on January 1, 2001. For a description of all of the assumptions used in preparing the summary pro forma financial data, you should read the notes to the pro forma financial statements for Crosstex Energy, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.
We define EBITDA as income (loss) before income taxes plus depreciation and amortization expense and interest expense. As described in the following paragraph, we use EBITDA as a supplemental measurement to evaluate our business. We also understand that such data is used by investors to determine our historical ability to service our indebtedness and make cash distributions to unitholders. However, the term EBITDA is not defined under generally accepted accounting principles and EBITDA is not a measurement of operating income, operating performance or liquidity presented in accordance with generally accepted accounting principles. You should not consider this data in isolation or as a substitute to net income as an indicator of our operating performance, cash flows from operating activities or other cash flow data calculated in accordance with generally accepted accounting principles. You should also not consider EBITDA as a measure of liquidity. Our EBITDA may not be comparable to EBITDA or similarly titled measures of other entities as other entities may not calculate EBITDA in the same manner as we do.
We use EBITDA as a supplemental financial measure to assess:
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Consequently, we use this supplemental financial measure when assessing liquidity and performance over time, and in comparison to companies that own similar assets and that our management believes calculate EBITDA in a manner similar to us. Although we use EBITDA to assess our ability to generate cash sufficient to pay interest costs and make cash distributions to our unitholders, the amount of cash available for such payments may be subject to our ability to reserve cash for other uses, such as debt repayments, capital expenditures and operating activities.
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them.
We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included in this prospectus. 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. — Historical(1) |
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Predecessor |
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Crosstex Energy, L.P. Pro Forma |
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Successor |
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Four Months Ended April 30, |
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Year Ended December 31, |
Eight Months Ended December 31, |
Year Ended December 31, |
Nine Months Ended September 30, |
Year Ended December 31, |
Nine Months Ended September 30, |
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(in thousands, except per unit amounts and operating data) |
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| Statement of Operations Data: | ||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||
| Midstream | $ | 7,896 | $ | 3,591 | $ | 88,008 | $ | 362,673 | $ | 270,496 | $ | 311,453 | $ | 362,340 | $ | 311,279 | ||||||||||||
| Treating | 9,770 | 5,947 | 17,392 | 24,353 | 19,084 | 10,631 | 24,353 | 10,631 | ||||||||||||||||||||
| Total revenues | 17,666 | 9,538 | 105,400 | 387,026 | 289,580 | 322,084 | 386,693 | 321,910 | ||||||||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||||||||||
| Midstream purchased gas | 5,154 | 2,746 | 83,672 | 344,755 | 258,670 | 294,025 | 344,493 | 293,916 | ||||||||||||||||||||
| Treating purchased gas | 8,110 | 4,731 | 14,876 | 18,078 | 14,854 | 3,996 | 18,078 | 3,996 | ||||||||||||||||||||
| Operating expenses | 986 | 544 | 1,796 | 7,430 | 4,995 | 7,732 | 7,313 | 7,643 | ||||||||||||||||||||
| General and administrative | 2,078 | 810 | 2,010 | 5,914 | 4,367 | 6,247 | 5,914 | 4,500 | ||||||||||||||||||||
| Stock based compensation | — | 8,802 | — | — | — | 33 | — | 33 | ||||||||||||||||||||
| Impairments | 538 | — | — | 2,873 | — | 3,150 | — | 3,150 | ||||||||||||||||||||
| (Profit) loss on energy trading contracts | (1,764 | ) | (638 | ) | (1,253 | ) | 3,714 | (1,527 | ) | (2,916 | ) | 3,714 | (2,916 | ) | ||||||||||||||
| Depreciation and amortization | 1,286 | 522 | 2,261 | 6,101 | 4,181 | 6,034 | 5,802 | 5,884 | ||||||||||||||||||||
| Total operating costs and expenses | 16,388 | 17,517 | 103,362 | 388,865 | 285,540 | 318,301 | 385,314 | 316,206 | ||||||||||||||||||||
| Operating income (loss) | 1,278 | (7,979 | ) | 2,038 | (1,839 | ) | 4,040 | 3,783 | 1,379 | 5,704 | ||||||||||||||||||
| Other income (expense): | ||||||||||||||||||||||||||||
| Interest expense, net | (638 | ) | (79 | ) | (530 | ) | (2,253 | ) | (1,538 | ) | (2,399 | ) | (147 | ) | (1,204 | ) | ||||||||||||
| Other income (expense) | (138 | ) | 381 | 115 | 174 | 145 | 73 | 174 | 73 | |||||||||||||||||||
| Total other income (expense) | (776 | ) | 302 | (415 | ) | (2,079 | ) | (1,393 | ) | (2,326 | ) | 27 | (1,131 | ) | ||||||||||||||
| Net income (loss) | $ | 502 | $ | (7,677 | ) | $ | 1,623 | $ | (3,918 | ) | $ | 2,647 | $ | 1,457 | $ | 1,406 | $ | 4,573 | ||||||||||
| Pro forma net income per limited partner unit | $ | 0.20 | $ | 0.64 | ||||||||||||||||||||||||
| Balance Sheet Data (at period end): | ||||||||||||||||||||||||||||
| Working capital surplus (deficit) | $ | (3,483 | ) | $ | (4,005 | ) | $ | 5,861 | $ | (2,254 | ) | $ | (2,446 | ) | $ | (8,598 | ) | $ | (8,598 | ) | ||||||||
| Property and equipment, net | 8,072 | 10,540 | 37,242 | 84,951 | 81,524 | 92,443 | 91,143 | |||||||||||||||||||||
| Total assets | 36,497 | 45,051 | 201,268 | 168,376 | 154,216 | 214,862 | 211,095 | |||||||||||||||||||||
| Long-term debt | 5,389 | 7,000 | 22,000 | 60,000 | 49,500 | 43,250 | 11,050 | |||||||||||||||||||||
| Partners' equity | 3,242 | 3,608 | 40,354 | 41,155 | 47,804 | 55,820 | 84,253 | |||||||||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||||||||||
| Net cash flow provided by (used in): | ||||||||||||||||||||||||||||
| Operating activities | $ | 1,404 | $ | 7,380 | $ | 7,741 | $ | (8,326 | ) | $ | 10,397 | $ | 15,087 | |||||||||||||||
| Investing activities | (1,342 | ) | (2,849 | ) | (25,643 | ) | (52,535 | ) | (47,255 | ) | (12,689 | ) | ||||||||||||||||
| Financing activities | (857 | ) | 198 | 36,557 | 42,558 | 32,200 | (2,750 | ) | ||||||||||||||||||||
| Other Financial Data: | ||||||||||||||||||||||||||||
| EBITDA(2) | $ | 2,426 | $ | (7,076 | ) | $ | 4,414 | $ | 4,436 | $ | 8,366 | $ | 9,890 | $ | 7,355 | $ | 11,661 | |||||||||||
| Maintenance capital expenditures | 57 | 1,922 | 1,228 | 1,267 | 1,922 | 1,267 | ||||||||||||||||||||||
| Expansion capital expenditures | 25,743 | 50,766 | 46,116 | 11,509 | 50,766 | 11,509 | ||||||||||||||||||||||
| Total capital expenditures | $ | 25,800 | $ | 52,688 | $ | 47,344 | $ | 12,776 | $ | 52,688 | $ | 12,776 | ||||||||||||||||
| Operating Data: | ||||||||||||||||||||||||||||
| Pipeline throughput (MMBtu/d) | 19,712 | 23,098 | 104,185 | 313,103 | 290,591 | 393,261 | 313,103 | 393,261 | ||||||||||||||||||||
| Natural gas processed (MMBtu/d) | 23,112 | 30,699 | 15,661 | 60,629 | 47,776 | 86,753 | 57,775 | 84,136 | ||||||||||||||||||||
| Treating volumes (MMBtu/d)(3) | 12,896 | 26,872 | 35,910 | 62,782 | 57,663 | 98,039 | 62,782 | 98,039 | ||||||||||||||||||||
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SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Crosstex Energy GP, L.P., our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary" duty. However, because Crosstex Energy GP, L.P. is indirectly owned by Crosstex Energy Holdings Inc., the officers and directors of Crosstex Energy GP, LLC, who manage and operate our general partner, have fiduciary duties to manage the business of our general partner in a manner beneficial to Crosstex Energy Holdings Inc. The officers and directors of Crosstex Energy GP, LLC have significant relationships with, and responsibilities to, Crosstex Energy Holdings Inc. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary responsibilities of our general partner, please read "Conflicts of Interest and Fiduciary Responsibilities."
Our general partner is permitted to resolve conflicts of interest by considering the interests of all the parties involved. Therefore, our general partner can consider the interests of its affiliates if a conflict of interest arises between the common unitholders and our general partner and its affiliates. Crosstex Energy GP, LLC will have a conflicts committee, consisting of at least two independent members of its board of directors, that will be available to review matters involving conflicts of interest. We expect that C. Roland Haden, Stephen A. Wells and Robert F. Murchison, all of whom will become directors of Crosstex Energy GP, LLC upon completion of this offering, will be members of the conflicts committee. Please read "Management—Directors and Executive Officers of Crosstex Energy GP, LLC" for a discussion of the directors of Crosstex Energy GP, LLC.
Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.
We will enter into an agreement with Crosstex Energy Holdings Inc. whereby it will generally agree not to engage in the business of gathering, transmitting, treating, processing and marketing of natural gas. In addition, our general partner will not receive any management fee or other compensation for its management of us but our general partner and its affiliates will be reimbursed for general and administrative expenses incurred on our behalf. For the twelve months following this offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. For a more detailed discussion of these agreements, please read "Certain Relationships and Related Transactions."
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Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors, which we believe include the risks material to our business, together with all of the other information included in this prospectus in evaluating an investment in the common units.
If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Inherent in Our Business
We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay the minimum quarterly distribution each
quarter.
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay our general partner's fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things;
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
Because of these factors, we may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Furthermore, you should also be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial
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reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after the offering is approximately $14.3 million. If we had completed the transactions contemplated in this prospectus on January 1, 2001, pro forma available cash from operating surplus generated during the year ended December 31, 2001 would have been approximately $5.3 million. If we had completed the transactions contemplated in this prospectus on January 1, 2002, pro forma available cash from operating surplus generated during the nine months ended September 30, 2002 would have been approximately $9.2 million. The amount of pro forma cash available for distribution during 2001 and the first nine months of 2002 would have been sufficient to allow us to pay the minimum quarterly distribution on all the common units and 5.5% and 78.7%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2001 and for the nine months ended September 30, 2002, please read "Cash Available for Distribution" and Appendix D.
The assumptions underlying the financial forecast in Appendix E are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual
results to differ materially from those forecasted.
The financial forecast set forth in Appendix E includes our forecast of statements of operations for the twelve months ending September 30, 2003. The financial forecast has been prepared by management and we have not received an opinion or report on it from any independent accountants. In addition, Appendix E includes a calculation of available cash from operating surplus based on the financial forecast. The assumptions underlying the financial forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we may not be able to pay the full minimum quarterly distributions or any amount on the common units or subordinated units, in which event the market price of the common units may decline materially.
We must continually compete for natural gas supplies, and any decrease in our supplies of natural gas could reduce our ability to make distributions to our unitholders.
Competition is intense in many of our markets. The principal areas of competition include obtaining gas supplies and the marketing and transportation of natural gas and NGLs. Our competitors include major integrated oil companies, interstate and intrastate pipelines and natural gas gatherers and processors. Our competitors in the Texas Gulf Coast area include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services. Some of our competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do.
If we are unable to maintain or increase the throughput on our systems by accessing new natural gas supplies to offset the natural decline in reserves, our business and financial results could be materially adversely affected. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.
In order to maintain or increase throughput levels in our natural gas gathering systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas
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supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near our gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production for a prolonged period along the Texas Gulf Coast, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on our results of operations and financial position. See "Business—Natural Gas Supply" for more information on our supplies of natural gas.
A substantial portion of our assets are connected to natural gas reserves that will decline over time, and the cash flows associated with those assets will accordingly decline.
A substantial portion of our assets, including our gathering systems and our treating plants, are dedicated to certain natural gas reserves and wells for which the production will naturally decline over time. Accordingly, our cash flows associated with these assets will also decline. If we are unable to access new supplies of natural gas either by connecting additional reserves to our existing assets or by constructing or acquiring new assets that have access to additional natural gas reserves, our ability to make distributions to our unitholders could decrease.
Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.
We are subject to significant risks due to fluctuations in commodity prices. These risks are based upon two components of our business: (1) the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; and (2) certain processing contracts for our Gregory system whereby we are exposed to natural gas and NGL commodity price risks.
The margins we realize from purchasing and selling a portion of the natural gas that we transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of the index price. For the nine months ended September 30, 2002, we purchased approximately 6.5% of our gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact on our results of operations.
A portion of our profitability is affected by the relationship between natural gas and NGL prices. For a component of our Gregory system volumes, we purchase natural gas, process natural gas and extract NGLs, and then sell the processed natural gas and NGLs. Since we extract Btus from the gas stream in the form of the liquids or consume it as fuel during processing, we reduce the Btu content of the natural gas. Accordingly, our margins under these arrangements can be negatively affected in periods in which the value of natural gas is high relative to the value of NGLs. For example, a decrease of $.01 per gallon in the price of NGLs and an increase of $0.10 per MMBtu in the average price of natural gas for the nine months ended September 30, 2002 would have resulted in decreases in processing margins of approximately $341,600. For the nine months ended September 30, 2002, we purchased approximately 46% of the natural gas volumes on our Gregory system under such contracts.
In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, in 2001, the NYMEX settlement price for the prompt month contract ranged from a high of $9.98 per MMBtu to a low of $1.83 per MMBtu. In the first nine months of 2002, the same index ranged from $3.47 per MMBtu to $2.01 per MMBtu. A composite of the OPIS Mt. Belvieu monthly average liquids price based upon our average liquids composition in 2001 ranged from a high of approximately $0.71 per gallon to a low of approximately $0.27 per gallon.
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In the first nine months of 2002, the same composite ranged from approximately $0.44 per gallon to approximately $0.27 per gallon.
We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or deliver in excess of contracted volumes, or a consumer could purchase less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
We are exposed to the credit risk of our customers, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.
Risks of nonpayment and nonperformance by our customers are a major concern in our business. Several of our customers have been receiving heightened scrutiny from the financial markets in light of the collapse of Enron Corp. We are subject to risks of loss resulting from nonpayment or nonperformance by these and other customers. We recognized a charge of $5.7 million in 2001 for sales contracts with Enron. These contracts related to our producer services operations in which we purchased and sold natural gas that did not move on our gathering and transmission systems. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve.
For the nine months ended September 30, 2002, approximately 63% of our sales of gas which were transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the
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end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
We depend on certain key customers, and the loss of any of our key customers could adversely affect our financial results.
We currently derive a significant portion of our revenues from contracts with a subsidiary of Kinder Morgan Inc., and we have entered into gas sales contracts with Entex Gas Resources, the local gas distribution company for the city of Houston, which commenced July 1, 2002. To the extent that these and other customers may reduce volumes of natural gas purchased under existing contracts, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers. Sales to the subsidiary of Kinder Morgan accounted for 28.2% of our revenues during the first nine months of 2002 and 23.9% of our revenues during 2001. Our agreements with our key customers provide for minimum volumes of natural gas that each customer must purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Our customers may default on their obligations to purchase the minimum volumes required under the applicable agreements. Our primary contract with Kinder Morgan expires in March 2006 and our contract with Entex expires in July 2004.
Our rapid growth may cause difficulties integrating new operations, and we have a limited combined operating history.
Since January 2000, we have made 10 acquisitions with an aggregate purchase price of approximately $60.6 million that have significantly increased our asset base. Unexpected costs or challenges may arise whenever different operations are combined. Any acquisition involves potential integration risks, including:
If we are unable to successfully integrate the companies, businesses or assets that we have acquired or in the future may acquire, our revenues may decline and we could, therefore, experience a material adverse effect on our business, financial condition or results of operations.
As a result of our rapid growth, our long-term debt has increased from approximately $3.6 million at December 31, 1997 to $43.3 million at September 30, 2002, an increase of approximately 1,100%.
Because we have grown rapidly, we have a limited operating history for most of our operations to which you may look to evaluate our performance. As a result, the historical and pro forma information may not give you an accurate indication of what our actual results would have been if the acquisitions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.
One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new processing and treating facilities. We have no material commitments for expansion projects as of the date of this prospectus. However, we are
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currently studying the possibility of expanding the capacity of our Gregory processing plant by 70,000 Mcf/d at an estimated cost ranging from $7.1 million to $9.2 million. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.
Our operations are subject to the many hazards inherent in the gathering, compressing, treating and processing of natural gas and storage of residue gas, including:
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our operations are concentrated in the Texas Gulf Coast, and a natural disaster or other hazard affecting this region could have a material adverse effect on our operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline systems which would cover damage to the pipelines. We are not insured against all environmental accidents which might occur, other than those considered to be sudden and accidental. Our business interruption insurance covers only our Gregory processing plant. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.
Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and future war or risk of war may adversely impact our results of operations.
The impact that the terrorist attacks of September 11, 2001 may have on the energy industry in general, and on us in particular, is not known at this time. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror.
The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to the September 11 attacks have made certain types of insurance more difficult for us to obtain. Our insurance policies now generally exclude acts of terrorism as compared to our policies prior to September 11, 2001. Such insurance is not available at what we believe to be acceptable pricing levels. A lower level of economic activity could also result in a decline in energy consumption, which could
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adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.
As of September 30, 2002, our total long-term indebtedness was approximately $43.3 million. Upon completion of the offering, we expect our total outstanding long-term indebtedness to be approximately $11.1 million, including approximately $10.3 million under our credit facility and $0.8 million of other indebtedness. Our payments of principal and interest on the indebtedness will reduce the cash available for distribution on the units. We will be prohibited by our credit facility from making cash distributions during an event of default under any of our indebtedness. Furthermore, our leverage and various limitations in the credit facility may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Federal, state or local regulatory measures could adversely affect our business.
While the Federal Energy Regulatory Commission, or FERC, does not regulate any of our operations, directly or indirectly, it influences certain aspects of our business and the market for our products. As a raw natural gas gatherer we generally are exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects our business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Some of our intrastate natural gas transmission pipelines are subject to regulation as a common carrier and as a gas utility by the Texas Railroad Commission, or TRRC. The TRRC's jurisdiction extends to both rates and pipeline safety. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business may be adversely affected.
Other state and local regulations also affect our business. We are subject to ratable take and common purchaser statutes in the states where we operate. Ratable take statues generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Oklahoma and Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.
The states in which we conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968. The "rural gathering exemption" under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The "rural gathering exemption," however, may be restricted in the future, and it does not apply to our natural gas transmission
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pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements. See "Business—Regulation."
Our business involves hazardous substances and may be adversely affected by environmental regulation.
Many of the operations and activities of our gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from our facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters containing mercury. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. See "Business—Environmental Matters."
Our use of derivative financial instruments has in the past and could in the future result in financial losses or reduce our income.
We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions, and we use futures and option contracts traded on the New York Mercantile Exchange. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. We currently have in place hedges on 100,000 MMBtu of gas per month at average prices ranging between $2.91 per MMBtu and $3.65 per MMBtu for the twelve month period from October 1, 2002 to September 30, 2003. This quantity represents approximately 76% of the margin on natural gas that we buy at a percentage of index and upon which we are exposed to the risk of fluctuations in natural gas prices. We could incur financial losses or fail to recognize the full value of a market opportunity as a result of volatility in the market values of the underlying commodities or if one of our counterparties fails to perform under a contract. For additional information about our risk management activities, including our use of derivative financial instruments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk."
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Due to our lack of asset diversification, adverse developments in our gathering, transmission, treating, processing and producer services businesses would reduce our ability to make distributions to our unitholders.
We rely exclusively on the revenues generated from our gathering, transmission, treating, processing and producer services businesses, and as a result our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
Our success depends on key members of our management, the loss of whom could disrupt our business operations.
We depend on the continued employment and performance of the officers of the general partner of our general partner and key operational personnel. The general partner of our general partner has entered into employment agreements with each of its executive officers. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any "key man" life insurance for any officers. See "Management."
Risks Inherent in an Investment in Us
Crosstex Energy Holdings Inc. will own a 70% limited partner interest in us and will control our general partner. Our general partner has conflicts of interest and limited fiduciary
responsibilities, which may permit our general partner to favor its own interests to the detriment of our unitholders.
Following this offering, Crosstex Energy Holdings Inc. will indirectly own an aggregate limited partner interest of approximately 70% in us and will own and control our general partner. Due to its control of our general partner and the size of its limited partnership interest in us, Crosstex Energy Holdings Inc. will be able to effectively control all limited partnership decisions, including any decisions related to the removal of our general partner. Conflicts of interest may arise in the future between Crosstex Energy Holdings Inc. and its affiliates, including our general partner, on the one hand, and our partnership or any of the unitholders, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations:
Conflicts Relating to Control:
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Conflicts Relating to Costs:
Please read "Conflicts of Interest and Fiduciary Responsibilities" and "Certain Relationships and Related Transactions—Omnibus Agreement."
Our unitholders will have no right to elect our general partner or the directors of its general partner and will have limited ability to remove our general partner.
Unlike the holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of its general partner and will have no right to elect our general partner or the board of directors of its general partner on an annual or other continuing basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 662/3% of the outstanding units voting together as a single class. Because affiliates of the general partner will control approximately 71.4% of all the units, the general partner currently cannot be removed without the consent of the general partner and its affiliates. Also, if the general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal without cause would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units which would otherwise have continued until we had met certain distribution and performance tests.
Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include, in most cases, charges of poor management of the business, so the removal of the general partner because of the unitholders' dissatisfaction with the general partner's performance in managing our partnership will most likely result in the termination of the subordination period.
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In addition, unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.
As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first negotiating such a purchase with our general partner and, as a result, you are less likely to receive a takeover premium.
Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to you.
Prior to making any distributions on the units, we will reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make distributions to you. Our general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner in its sole discretion. See "Management—Reimbursement of Expenses of the General Partner."
The control of our general partner may be transferred to a third party, and that third party could replace our current management team, in each case without unitholder consent.
The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.
Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.
Our partnership agreement contains provisions which reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to the unitholders. The partnership agreement also restricts the remedies available to unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law. See "Conflicts of Interest and Fiduciary Responsibilities."
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You will experience immediate and substantial dilution in net tangible book value of $9.71 per common unit.
The initial public offering price of $20.00 per unit exceeds pro forma net tangible book value of $10.29 per unit. As a result, you will incur immediate and substantial dilution of $9.71 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with generally accepted accounting principles. Please read "Dilution."
We may issue additional common units without your approval, which would dilute your ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,166,500 additional common units (1,316,500 additional common units if the underwriters' over-allotment option is exercised in full). Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common
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units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, our general partner and its affiliates will own 14.3% of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 71.4% of the common units. For additional information about the call right, please read "The Partnership Agreement—Limited Call Right."
You may not have limited liability if a court finds that unitholder action constitutes control of our business.
You could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business, to the extent that a person who has transacted business with the partnership reasonably believes, based on your conduct, that you are a general partner. Our general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Please read "The Partnership Agreement—Limited Liability" for a discussion of the implications of the limitations on liability to a unitholder.
Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.
Prior to the offering, there has been no public market for the common units. After the offering, there will be only 2,000,000 publicly-traded units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
Restrictions in our credit facility could limit our ability to make distributions to our unitholders.
We will enter into a new, $67.5 million credit facility in connection with the closing of this offering. The credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to our unitholders. The credit facility also contains covenants requiring us to maintain certain financial ratios, such as debt to EBITDA, EBITDA to interest and current assets to current liabilities. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the credit facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Facility" for a discussion of our credit facility.
You are urged to read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
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The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay tax on our income at corporate rates of up to 35% (under current law) and we would probably pay state income taxes as well. In addition, distributions to you would generally be taxed again to you as corporate distributions and no income, gains, losses, or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, the cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you and thus would likely result in a material reduction in the value of the common units.
A change in current law or a change in our business could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be decreased to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the costs of any contest will be borne by us and therefore indirectly by our unitholders and
our general partner.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel's conclusions expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with all of our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which common units trade. In addition, our costs of any contest with the IRS will be borne by us and therefore indirectly by our unitholders and our general partner.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
You will be required to pay federal income taxes and, in some cases, state, local, and foreign income taxes on your share of our taxable income even if you do not receive cash distributions from us. You may not receive cash distributions equal to your share of our taxable income or even the tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be different than expected.
If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, will likely be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased
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income in prior years. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities, regulated investment companies, and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company or mutual fund. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income.
We will register as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.
We intend to register with the IRS as a "tax shelter." We will advise you of our tax shelter registration number once that number has been assigned. The tax laws require that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.
We will determine the tax benefits that are available to an owner of units without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
As a result of investing in our common units, you will likely be subject to state and local taxes and return filing requirements in jurisdictions where you do not live.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state, local and foreign income tax returns and pay state, local and foreign income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in Texas, Oklahoma, Louisiana, New Mexico and Arkansas. Oklahoma, Louisiana, New Mexico and Arkansas impose an income tax, generally. Texas does not impose a state income tax on individuals, but does impose a franchise tax on limited liability companies and corporations in certain circumstances. We may do business or own property in other states or foreign countries in the future. It is your responsibility to file all federal, state, local, and foreign tax returns. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.
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We expect to receive net proceeds of approximately $34.7 million (or $40.3 million if the underwriters exercise their over-allotment option) from the sale of the 2,000,000 common units offered by this prospectus, after deducting underwriting discounts and estimated offering expenses. We intend to use approximately $32.2 million of the net proceeds of this offering to repay outstanding borrowings under our new bank credit facility, which replaced our predecessor's credit facility, and $2.5 million of the net proceeds of this offering to make a distribution to Crosstex Energy Holdings Inc.
As of September 30, 2002, total borrowings under our predecessor's bank credit facility were approximately $42.5 million and had a weighted average interest rate of 3.9%. Our predecessor incurred all of the debt under its bank credit facility for acquisitions and for working capital purposes. Our new credit facility will be effective at the closing of this offering. Our new credit facility will contain a $47.5 million acquisition facility, approximately $10.3 million of which will be outstanding at the closing of this offering, and a $20.0 million working capital facility. Approximately $15.0 million of letters of credit will be outstanding at the closing of this offering, which amounts reduce our availability under our working capital facility but are not treated as debt on our balance sheet. The acquisition and working capital facilities will bear interest at a rate of LIBOR plus 1.625% to 2.875% or the bank's reference rate plus 0.125% to 1.375%, depending on our leverage ratio. If our new credit facility had been in place at September 30, 2002, our weighted average interest rate would have been 3.9%. The acquisition facility will convert into a term loan on April 30, 2004, the term loan will mature on April 30, 2007 and the working capital facility will mature on April 30, 2004. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Facility" for a description of our new credit facility.
We will use any net proceeds from the exercise of the over-allotment option to repay borrowings under our credit facility.
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The following table shows:
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
| |
As of September 30, 2002 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Actual |
Pro Forma |
||||||||
| |
(in thousands) |
|||||||||
| Total debt | $ | 43,300 | $ | 11,100 | ||||||
Partners' equity: |
||||||||||
| Partners' equity | 56,503 | — | ||||||||
| Common unitholders | — | 37,953 | ||||||||
| Subordinated unitholders | — | 45,588 | ||||||||
| General partner interest | — | 1,395 | ||||||||
| Other comprehensive income | (683 | ) | (683 | ) | ||||||
| Total partners' equity | 55,820 | 84,253 | ||||||||
| Total capitalization | $ | 99,120 | $ | 95,353 | ||||||
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Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2002 after giving effect to the offering of common units and the related transactions and assuming that the underwriters' over-allotment option is not exercised, our net tangible book value was $73.5 million, or $10.29 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
| Initial public offering price per common unit | $ | 20.00 | ||||
| Pro forma net tangible book value per common unit before the offering (1) | $ | 7.55 | ||||
| Increase in net tangible book value per common unit attributable to purchasers in the offering | 2.74 | |||||
| Less: Pro forma net tangible book value per common unit after the offering (2) | 10.29 | |||||
| Immediate dilution in net tangible book value per common unit to new investors | $ | 9.71 | ||||
The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner, its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.
| |
Units Acquired |
Total Consideration |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Number |
Percent |
Amount |
Percent |
|||||||
| |
|
|
(in thousands) |
|
|||||||
| General partner and affiliates (1)(2) | 5,142,857 | 72.0 | % | $ | 50,236 | 55.7 | % | ||||
| New investors | 2,000,000 | 28.0 | % | 40,000 | 44.3 | % | |||||
| Total | 7,142,857 | 100.0 | % | $ | 90,236 | 100.0 | % | ||||
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Distributions of Available Cash
General. Within approximately 45 days after the end of each quarter, beginning with the quarter ending March 31, 2003, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through March 31, 2003 based on the actual length of the period.
Definition of Available Cash. Available Cash means, for any quarter ending prior to liquidation:
provided, however, that the general partner may not establish cash reserves for distributions to the subordinated units unless the general partner has determined that, in its judgment, the establishment of reserves will not prevent Crosstex Energy, L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for the next four quarters; and
provided, further, that disbursements made by Crosstex Energy, L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the general partner so determines.
Minimum Quarterly Distribution. Common units are entitled to receive distributions from operating surplus of $.50 per quarter, or $2.00 on an annualized basis, before any distributions are paid on our subordinated units. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility.
Contractual Restrictions on our Ability to Distribute Available Cash. Our ability to distribute available cash is contractually restricted by the terms of the credit facility we will enter into in connection with the closing of this offering. The credit facility will contain covenants requiring us to maintain certain financial ratios, such as debt to EBITDA, EBITDA to interest and current assets to current liabilities. We will be prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the credit facility.
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Operating Surplus and Capital Surplus
General. All cash distributed to unitholders will be characterized either as "operating surplus" or "capital surplus." We distribute available cash from operating surplus differently than available cash from capital surplus.
Definition of Operating Surplus. We define operating surplus in the glossary, and for any period it generally means:
As reflected above, our definition of operating surplus includes $8.9 million in addition to our cash balance on the closing date of this offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $8.9 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus.
Definition of Capital Surplus. We also define capital surplus in the glossary, and it will generally be generated only by:
Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. While we do not currently anticipate that we will make any distributions from capital surplus in the near term, we may determine that the sale or disposition of an asset or business owned or acquired by us may be beneficial to our unitholders. If we distribute to you the equity we own in a subsidiary or the proceeds from the sale of one of our businesses, such a distribution would be characterized as a distribution from capital surplus.
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General. During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
Definition of Subordination Period. We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after December 31, 2007 that each of the following tests are met:
Early Conversion of Subordinated Units. Before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:
The early conversions will occur if at the end of the applicable quarter each of the following three tests are met:
However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.
Definition of Adjusted Operating Surplus. We define "adjusted operating surplus" in the glossary, and for any period it generally means:
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Adjusted Operating Surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.
Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:
Distributions of Available Cash from Operating Surplus During the Subordination Period
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
Distributions of Available Cash from Operating Surplus After the Subordination Period
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
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Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.
If for any quarter:
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
Target Amount of Quarterly Distribution
The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders, our general partner and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our unitholders, our general partner and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
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| |
|
Marginal Percentage Interest in Distributions |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| |
Total Quarterly Distribution Target Amount |
Unitholders |
General Partner |
Holders of Incentive Distribution Rights |
|||||
| Minimum Quarterly Distribution | $0.50 | 98 | % | 2 | % | — | |||
| First Target Distribution | above $0.50 up to $0.625 | 85 | % | 2 | % | 13 | % | ||
| Second Target Distribution | above $0.625 up to $0.75 | 75 | % | 2 | % | 23 | % | ||
| Thereafter | above $0.75 | 50 | % | 2 | % | 48 | % | ||
Distributions from Capital Surplus
How Distributions from Capital Surplus will be Made. We will make distributions of available cash from capital surplus in the following manner:
Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of incentive distribution rights and 2% to our general partner.
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units we will proportionately adjust:
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For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.
In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.
Distributions of Cash upon Liquidation
General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.
Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:
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If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.
Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the
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capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.
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CASH AVAILABLE FOR DISTRIBUTION
We intend to pay each quarter, to the extent we have sufficient available cash from operating surplus, the minimum quarterly distribution of $0.50 per unit, or $2.00 per year, on all the common units and subordinated units. Available cash for any quarter will consist generally of all cash on hand at the end of that quarter, plus working capital borrowings after the end of the quarter, as adjusted for reserves. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus working capital borrowings after the end of the quarter, plus $8.9 million. The definitions of available cash and operating surplus are in the glossary.
The amounts of available cash from operating surplus needed to pay the minimum quarterly distribution for one quarter and for four quarters on the common units and the subordinated units and to pay the related distribution on the general partner interest to be outstanding immediately after this offering are approximately:
| |
One Quarter |
Four Quarters |
|||||
|---|---|---|---|---|---|---|---|
| |
(in thousands) |
||||||
| Common Units | $ | 1,167 | $ | 4,666 | |||
| Subordinated Units | 2,334 | 9,334 | |||||
| 2% General Partner Interest | 71 | 286 | |||||
| Total | $ | 3,572 | $ | 14,286 | |||
Pro forma available cash from operating surplus from prior periods would not have been sufficient to pay the minimum quarterly distribution on all units.
If we had completed the transactions contemplated in this prospectus on January 1, 2001, pro forma available cash from operating surplus generated during 2001 would have been approximately $5.3 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 5.5% of the minimum quarterly distribution on the subordinated units for that period. If we had completed the transactions contemplated in this prospectus on January 1, 2002, pro forma available cash from operating surplus generated during the nine months ended September 30, 2002 would have been approximately $9.2 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 78.7% of the minimum quarterly distribution on the subordinated units for that period.
We derived the amounts of pro forma available cash from operating surplus shown above from our pro forma financial statements in the manner described in Appendix D. The pro forma adjustments are based upon currently available information and specific estimates and assumptions. The pro forma financial statements do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, available cash from operating surplus as defined in the partnership agreement is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should only view the amount of pro forma available cash from operating surplus as a general indication of the amount of available cash from operating surplus that we might have generated had we been formed in earlier periods. A more complete explanation of the pro forma adjustments can be found in the Notes to Our Unaudited Pro Forma Financial Statements.
Furthermore, pro forma available cash from operating surplus has not been reduced to reflect incremental general and administrative expenses, such as cost of tax return preparation, accounting
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support services, annual and quarterly reports to unitholders, investor relations and registrar and transfer agent fees, that we expect to incur at an annual rate of approximately $650,000.
We believe we will have sufficient available cash from operating surplus following the offering to pay the minimum quarterly distribution on all units through September 30, 2003.
We believe that, following completion of the offering, we will have sufficient available cash from operating surplus to allow us to make the full minimum quarterly distribution on all outstanding common and subordinated units for each quarter through September 30, 2003. Our belief is based on our financial forecast in Appendix E.
You should read the notes and the other information in Appendix E carefully for a discussion of the material assumptions underlying the financial forecast. The financial forecast presents, to the best of our knowledge and belief, the expected results of our operations for the forecast period. The financial forecast is based on certain assumptions and reflects our judgment of expected business and industry conditions. The assumptions disclosed herein are those that we believe are significant to the financial forecast. We believe our actual results of operations will approximate those reflected in the financial forecast; however, because events and circumstances frequently do not occur as expected, we can give you no assurance that the forecast results will be achieved. There will likely be differences between the forecast and the actual results and those differences may be material. If the forecast is not achieved, we may not be able to pay the full minimum quarterly distribution or any amount on the common units. The financial forecast has been prepared by management and we have not received an opinion or report on it from any independent accountants.
When considering the financial forecast, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors—Risks Inherent in Our Business" and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in Appendix E.
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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following table sets forth selected historical financial and operating data of our predecessor, Crosstex Energy Services, Ltd., as of and for the dates and periods indicated and the summary pro forma financial and operating data of Crosstex Energy, L.P. as of and for the year ended December 31, 2001 and the nine months ended September 30, 2002. The selected historical financial data for the years ended December 31, 1997, 1998, 1999 and 2001 and for the four months ended April 30, 2000 and the eight months ended December 31, 2000 are derived from the audited financial statements of Crosstex Energy Services, Ltd. and its predecessor. The selected historical financial data for the nine months ended September 30, 2001 and 2002 are derived from the unaudited financial statements of Crosstex Energy Services, Ltd. and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. As described in our historical financial statements, 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 audited 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, the selected historical financial and operating data of Crosstex Energy Services, Ltd. include the results of operations of the Arkoma system beginning in September 2000, the Gulf Coast system beginning in September 2000 and the CCNG system, which includes the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, beginning in May 2001.
The selected pro forma financial and operating data of Crosstex Energy, L.P. reflect the consolidated historical operating results of Crosstex Energy Services, Ltd., as adjusted for the offering and the related transactions. The summary pro forma financial data are derived from the unaudited pro forma financial statements. The pro forma balance sheet assumes that the offering and related transactions occurred on September 30, 2002. The pro forma statements of operations assume that the offering and related transactions occurred on January 1, 2001. For a description of all of the assumptions used in preparing the summary pro forma financial data, you should read the notes to the pro forma financial statements for Crosstex Energy, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.
We define EBITDA as operating income (loss) before income taxes plus depreciation and amortization expense and interest expense. As described in the following paragraph, we use EBITDA as a supplemental measurement to evaluate our business. We also understand that such data is used by investors to determine our historical ability to service our indebtedness and make cash distributions to unitholders. However, the term EBITDA is not defined under generally accepted accounting principles and EBITDA is not a measurement of operating income, operating performance or liquidity presented in accordance with generally accepted accounting principles. You should not consider this data in isolation or as a substitute to net income as an indicator of our operating performance, cash flows from operating activities or other cash flow data calculated in accordance with generally accepted accounting principles. You should also not consider EBITDA as a measure of liquidity. Our EBITDA may not be comparable to EBITDA or similarly titled measures of other entities as other entities may not calculate EBITDA in the same manner as we do.
We use EBITDA as a supplemental financial measure to assess:
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Consequently, we use this supplemental financial measure when assessing liquidity and performance over time, and in comparison to companies that own similar assets and that our management believes calculate EBITDA in a manner similar to us. Although we use EBITDA to assess our ability to generate cash sufficient to pay interest costs and make cash distributions to our unitholders, the amount of cash available for such payments may be subject to our ability to reserve cash for other uses, such as debt repayments, capital expenditures and operating activities.
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them.
We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included in this prospectus. The table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
45
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Crosstex Energy Services, Ltd.—Historical(1) |
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Crosstex Energy L.P. Pro Forma |
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Predecessor |
Successor |
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Years Ended December 31, |
Four Months Ended April 30, |
Eight Months Ended December 31, |
Year Ended December 31, |
Nine Months Ended September 30, |
Year Ended December 31, |
Nine Months Ended September 30, |
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1997 |
1998 |
1999 |
2000 |
2000 |
2001 |
2001 |
2002 |
2001 |
2002 |
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(in thousands, except per unit amounts and operating data) |
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| Statement of Operations Data: | ||||||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||||||
| Midstream | $ | 1,651 | $ | 7,181 | $ | 7,896 | $ | 3,591 | $ | 88,008 | $ | 362,673 | $ | 270,496 | $ | 311,453 | $ | 362,340 | $ | 311,279 | ||||||||||||||
| Treating | — | 1,647 | 9,770 | 5,947 | 17,392 | 24,353 | 19,084 | 10,631 | 24,353 | 10,631 | ||||||||||||||||||||||||
| Total revenues | 1,651 | 8,828 | 17,666 | 9,538 | 105,400 | 387,026 | 289,580 | 322,084 | 386,693 | 321,910 | ||||||||||||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||||||||||||||||
| Midstream purchased gas | 1,194 | 5,561 | 5,154 | 2,746 | 83,672 | 344,755 | 258,670 | 294,025 | 344,493 | 293,916 | ||||||||||||||||||||||||
| Treating purchased gas | — | 1,025 | 8,110 | 4,731 | 14,876 | 18,078 | 14,854 | 3,996 | 18,078 | 3,996 | ||||||||||||||||||||||||
| Operating expenses | 28 | 871 | 986 | 544 | 1,796 | 7,430 | 4,995 | 7,732 | 7,313 | 7,643 | ||||||||||||||||||||||||
| General and administrative | 962 | 2,006 | 2,078 | 810 | 2,010 | 5,914 | 4,367 | 6,247 | 5,914 | 4,500 | ||||||||||||||||||||||||
| Stock based compensation | — | — | — | 8,802 | — | — | — | 33 | — | 33 | ||||||||||||||||||||||||
| Impairments | — | — | 538 | — | — | 2,873 | — | 3,150 | — | 3,150 | ||||||||||||||||||||||||
| (Profit) loss on energy trading contracts | (1,337 | ) | (1,402 | ) | (1,764 | ) | (638 | ) | (1,253 | ) | 3,714 | (1,527 | ) | (2,916 | ) | 3,714 | (2,916 | ) | ||||||||||||||||
| Depreciation and amortization | 177 | 843 | 1,286 | 522 | 2,261 | 6,101 | 4,181 | 6,034 | 5,802 | 5,884 | ||||||||||||||||||||||||
| Total operating costs and expenses | 1,024 | 8,904 | 16,388 | 17,517 | 103,362 | 388,865 | 285,540 | 318,301 | 385,314 | 316,206 | ||||||||||||||||||||||||
| Operating income (loss) | 627 | (76 | ) | 1,278 | (7,979 | ) | 2,038 | (1,839 | ) | 4,040 | 3,783 | 1,379 | 5,704 | |||||||||||||||||||||
| Other income (expense): | ||||||||||||||||||||||||||||||||||
| Interest expense, net | (157 | ) | (502 | ) | (638 | ) | (79 | ) | (530 | ) | (2,253 | ) | (1,538 | ) | (2,399 | ) | (147 | ) | (1,204 | ) | ||||||||||||||
| Other income (expense) | (282 | ) | 88 | (138 | ) | 381 | 115 | 174 | 145 | 73 | 174 | 73 | ||||||||||||||||||||||
| Total other income (expense) | (439 | ) | (414 | ) | (776 | ) | 302 | (415 | ) | (2,079 | ) | (1,393 | ) | (2,326 | ) | 27 | (1,131 | ) | ||||||||||||||||
| Net income (loss) | $ | 188 | $ | (490 | ) | $ | 502 | $ | (7,677 | ) | $ | 1,623 | $ | (3,918 | ) | $ | 2,647 | $ | 1,457 | $ | 1,406 | $ | 4,573 | |||||||||||
| Pro forma net income per limited partner unit | $ | 0.20 | $ | 0.64 | ||||||||||||||||||||||||||||||
| Balance Sheet Data (at period end): | ||||||||||||||||||||||||||||||||||
| Working capital surplus (deficit) | $ | (1,759 | ) | $ | (3,394 | ) | $ | (3,483 | ) | $ | (4,005 | ) | $ | 5,861 | $ | (2,254 | ) | $ | (2,446 | ) | $ | (8,598 | ) | $ | (8,598 | ) | ||||||||
| Property and equipment, net | 5,788 | 10,103 | 8,072 | 10,540 | 37,242 | 84,951 | 81,524 | 92,443 | 91,143 | |||||||||||||||||||||||||
| Total assets | 25,163 | 37,223 | 36,497 | 45,051 | 201,268 | 168,376 | 154,216 | 214,862 | 211,095 | |||||||||||||||||||||||||
| Long-term debt | 3,596 | 6,589 | 5,389 | 7,000 | 22,000 | 60,000 | 49,500 | 43,250 | 11,050 | |||||||||||||||||||||||||
| Partners' equity | 3,240 | 2,655 | 3,242 | 3,608 | 40,354 | 41,155 | 47,804 | 55,820 | 84,253 | |||||||||||||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||||||||||||||||
| Net cash flow provided by (used in): | ||||||||||||||||||||||||||||||||||
| Operating activities | $ | (126 | ) | $ | 3,963 | $ | 1,404 | $ | 7,380 | $ | 7,741 | $ | (8,326 | ) | $ | 10,397 | $ | 15,087 | ||||||||||||||||
| Investing activities | (2,208 | ) | (4,821 | ) | (1,342 | ) | (2,849 | ) | (25,643 | ) | (52,535 | ) | (47,255 | ) | (12,689 | ) | ||||||||||||||||||
| Financing activities | (2,502 | ) | 1,437 | (857 | ) | 198 | 36,557 | 42,558 | 32,200 | (2,750 | ) | |||||||||||||||||||||||
| Other Financial Data: | ||||||||||||||||||||||||||||||||||
| EBITDA(2) | $ | 522 | $ | 855 | $ | 2,426 | $ | (7,076 | ) | $ | 4,414 | $ | 4,436 | $ | 8,366 | $ | 9,890 | $ | 7,355 | $ | 11,661 | |||||||||||||
| Maintenance capital expenditures | 57 | 1,922 | 1,228 | 1,267 | 1,922 | 1,267 | ||||||||||||||||||||||||||||
| Expansion capital expenditures | 25,743 | 50,766 | 46,116 | 11,509 | 50,766 | 11,509 | ||||||||||||||||||||||||||||
| Total capital expenditures | $ | 25,800 | $ | 52,688 | $ | 47,344 | $ | 12,776 | $ | 52,688 | $ | 12,776 | ||||||||||||||||||||||
| Operating Data: | ||||||||||||||||||||||||||||||||||
| Pipeline throughput (MMBtu/d) | 10,603 | 16,435 | 19,712 | 23,098 | 104,185 | 313,103 | 290,591 | 393,261 | 313,103 | 393,261 | ||||||||||||||||||||||||
| Natural gas processed (MMBtu/d) | — | 13,394 | 23,112 | 30,699 | 15,661 | 60,629 | 47,776 | 86,753 | 57,775 | 84,136 | ||||||||||||||||||||||||
| Treating volumes (MMBtu/d)(3) | — | 3,982 | 12,896 | 26,872 | 35,910 | 62,782 | 57,663 | 98,039 | 62,782 | 98,039 | ||||||||||||||||||||||||
46
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 historical and pro forma combined financial statements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included in this prospectus.
We are a Delaware limited partnership formed by Crosstex Energy Holdings Inc. on July 12, 2002 to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the nine months ended September 30, 2002, 72% of our gross margin was generated in the Midstream division, with the balance in the Treating division, and approximately 85% of our gross margin was generated in the Texas Gulf Coast region.
Since our formation, we have grown significantly as a result of our construction and acquisition of gathering and transmission pipelines, treating plants and a processing plant. From January 1, 2000 through September 30, 2002, we have invested approximately $94.3 million to develop or acquire new assets. The purchased assets were acquired from numerous sellers at different periods throughout the year and were accounted for under the purchase method of accounting for business combinations. Accordingly, the results of operations for such acquisitions are included in our financial statements only from the applicable date of the acquisition. As a consequence, the historical results of operations for the periods presented may not be comparable.
Our results of operations are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facility or treated at our treating plants. We generate revenues from four primary sources:
The bulk of our operating profits are derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. 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
47
a percentage discount or premium to the index price for our principal gathering and transmission systems and for our producer services business for the nine months ended September 30, 2002.
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Nine Months Ended September 30, 2002 |
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|---|---|---|---|---|---|---|---|---|
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Gas Purchased |
Gas Sold |
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| Asset or Business |
Fixed Amount to Index |
Percentage of Index |
Fixed Amount to Index |
Percentage of Index |
||||
| |
(in billions of MMBtus) |
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| Gulf Coast system | 26.7 | 2.3 | 29.0 | — | ||||
| Corpus Christi system | 42.7 | 0.2 | 42.9 | — | ||||
| Gregory gathering system (1) | 20.9 | 2.7 | 23.6 | — | ||||
| Arkoma gathering system | — | 3.0 | 3.0 | — | ||||
| Producer services (2) | 60.3 | 2.1 | 62.4 | — | ||||
In addition to the margins generated by the Gregory gathering system, we generate revenues at our Gregory processing plant under two types of arrangements:
We generate producer services revenues through the purchase and resale of natural gas. We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 80 independent producers. We engage in such activities on more than 30 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.
We generate treating revenues under three arrangements:
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Typically, we incur minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through our pipeline assets. Therefore, we recognize a substantial portion of incremental gathering and transportation revenues as operating income.
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore, do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.
Our general and administrative expenses will be dictated by the terms of our partnership agreement and our omnibus agreement with Crosstex Energy Holdings Inc. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to Crosstex Energy, L.P., and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, Crosstex Energy, L.P. Our partnership agreement provides that our general partner will determine the expenses that are allocable to Crosstex Energy, L.P. in any reasonable manner determined by our general partner in its sole discretion. For the first 12 months following this offering, the amount which we will reimburse our general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on our behalf.
Crosstex Energy Holdings Inc. is considering modifying certain terms of outstanding options to purchase equity in it subsequent to the completion of this offering. These modifications could result in a new measurement date for the options. The resulting compensation expense, which may be significant, would be recognized by us over the remaining vesting period of the options as non-cash stock based compensation expense.
As described in the historical financial statements, 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. The transaction value of $21.9 million from the Yorktown investment was allocated to the assets and liabilities of our predecessor, which created increases in depreciation and amortization charges in periods subsequent to the Yorktown investment. The historical financial statements present separate reports for the entities before and after the transaction. For purposes of the analysis below, the year 2000 is considered one period, and the distinction in legal entities created by the transaction with Yorktown is ignored.
We have 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 Arkoma gathering system, the Gulf Coast system and the CCNG system.
We acquired the Arkoma gathering system in September 2000 for a purchase price of approximately $10.5 million. The Arkoma system consisted of approximately 84 miles of gathering lines
49
located in eastern Oklahoma. When acquired, the system was connected to approximately 115 wells, and purchased and resold approximately 12,000 MMBtu of gas per day.
We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million. The Gulf Coast system consisted of approximately 484 miles of gathering and transmission lines extending from south Texas to markets near the Houston area. At the time of the acquisition, it was transporting approximately 117,000 MMBtu of gas per day.
We acquired the CCNG system in May 2001 for a purchase price of approximately $30 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.
Certain assets and liabilities of our predecessor will not be contributed to our new partnership. These include receivables associated with the Enron Corp. bankruptcy discussed below under "—Results of Operations—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts," and any cost or benefit associated with the various puts and calls entered into to protect the value of our predecessor's position relative to the Enron matter. The Jonesville processing plant, which has been largely inactive since the beginning of 2001, and the recently acquired Clarkson plant will not be contributed.
Our 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 our 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 our profitability since the purchase price of a portion of the gas we buy (approximately 6.5% in the first nine months of 2002) is based on a percentage of a particular natural gas price index for a period, while the gas is resold at a fixed dollar relationship to the same index. Therefore, during periods of low gas prices, these contracts can be less profitable than during periods of higher gas prices. However, on most of the gas we buy and sell, margins are not affected by such changes because the gas is bought and sold at a fixed relationship to the relevant
50
index. Therefore, while changes in the price of gas can have very large impacts on revenues and cost of revenues, on this portion of the gas, the changes are equal and offsetting.
Gas prices can also affect our profitability indirectly by influencing drilling activity and related opportunities for gas gathering, treating, and processing.
Set forth in the table below is certain financial and operating data for the Midstream and Treating divisions for the periods indicated.
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Year Ended December 31, |
Nine Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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1999 |
2000 |
2001 |
2001 |
2002 |
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(in millions) |
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| Midstream revenues | $ | 7.9 | $ | 91.6 | $ | 362.7 | $ | 270.5 | $ | 311.5 | ||||||
| Midstream purchased gas | 5.2 | 86.4 | 344.8 | 258.7 | 294.0 | |||||||||||
| Midstream gross margin | 2.7 | 5.2 | 17.9 | 11.8 | 17.5 | |||||||||||
Treating revenues |
9.8 |
23.3 |
24.4 |
19.1 |
10.6 |
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| Treating purchased gas | 8.1 | 19.6 | 18.1 | 14.9 | 4.0 | |||||||||||
| Treating gross margin | 1.7 | 3.7 | 6.3 | 4.2 | 6.6 | |||||||||||
| Total gross margin | $ | 4.4 | $ | 8.9 | $ | 24.2 | $ | 16.0 | $ | 24.1 | ||||||
Midstream Volumes (MMBtu/d): |
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| Gathering and transportation | 19,712 | 77,527 | 313,103 | 290,591 | 393,261 | |||||||||||
| Processing | 23,112 | 20,605 | 60,629 | 47,776 | 86,753 | |||||||||||
| Producer services | 278,419 | 215,121 | 283,098 | 294,035 | 228,857 | |||||||||||
Treating Volumes (MMBtu/d) |
12,896 |
32,938 |
62,782 |
57,663 |
98,039 |
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Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001
Revenues. Midstream revenues were $311.5 million for the nine months ended September 30, 2002 compared to $270.5 million for the nine months ended September 30, 2001, an increase of $41.0 million, or 15%. Revenues were higher in 2002 than in 2001 due to the contribution of the Corpus Christi system, the Gregory gathering system and the Gregory processing plant, which generated $91.2 million in additional revenues in the first nine months of 2002 as these assets were not acquired until May 2001. In addition, Gulf Coast system volumes increased in 2002 by approximately 4,265 MMBtu per day, which generated an additional $3.5 million of revenue. This increase was partially offset by a decline in natural gas prices from an average NYMEX settlement price of $4.88 per MMBtu in 2001 to $2.97 in 2002, which caused a $58.9 million decline in revenues. In addition, Midstream revenues increased by $5.4 million due to a decrease in the elimination of intersegment sales in the first nine months of 2002 compared to the first nine months of 2001.
Treating revenues were $10.6 million in the first nine months of 2002 compared to $19.1 million in the same period in 2001, a decrease of $8.5 million, or 44%. The decline was due to the decrease in the price of natural gas, which accounted for $2.9 million of the decrease in treating revenues, a change in the contracts at certain plants to discontinue purchasing and reselling the treated gas and instead to receive only a treatment fee, which accounted for $5.4 million of the decrease in treating revenues, and volume declines at certain plants which accounted for $2.4 million of the decrease in treating revenues. This decline was partially offset by the acquisition of the Rosita plant in May 2001 and 16 new plants
51
placed in service in 2002, which collectively added $2.1 million to revenues for the nine months ended September 30, 2002.
Purchased Gas Costs. Midstream purchased gas costs were $294.0 million for the nine months ended September 30, 2002 compared to $258.7 million for the nine months ended September 30, 2001, an increase of $35.4 million, or 13.7%. Costs increased by $84.3 million due to the Corpus Christi system, the Gregory gathering system and the Gregory processing plant. These facilities were purchased in May 2001 and only five months of their operating results are included in the 2001 period. This increase was partially offset by the decline in natural gas prices discussed above, which reduced costs by $56.9 million. Midstream cost of sales also increased by $3.4 million due to the additional Gulf Coast volumes and $5.4 million because of the variance in intersegment eliminations as discussed with Midstream revenue.
Treating purchased gas costs were $4.0 million in the first nine months of 2002 compared to $14.9 million in the comparable period in 2001, a decrease of $10.9 million, or 73%. The decrease in natural gas prices caused $2.9 million of the decline, a decrease in treating volumes at certain plants caused $2.4 million of the decline and, as discussed above, certain contracts were restructured from a purchase and resale of the associated gas to a pure treatment fee, causing a decline of $5.5 million in purchased gas costs.
Operating Expenses. Operating expenses were $7.7 million for the nine months ended September 30, 2002, compared to $5.0 million for the nine months ended September 30, 2001, an increase of $2.7 million, or 55%. The increase was primarily associated with the CCNG assets purchased in May 2001.
General and Administrative Expenses. General and administrative expenses were $6.2 million for the nine months ended September 30, 2002 compared to $4.4 million for the nine months ended September 30, 2001, an increase of $1.9 million, or 43%. The increases were associated with increases in staffing associated with the requirements of the CCNG assets and in preparation for our initial public offering.
Impairments. Impairment expense was $3.2 million in the nine months of 2002 compared to zero in the same period of 2001. Impairment expense was due to the write off of intangible assets associated with contract values for two treating plants which had experienced recent declines in cash flows. The operator of the wells behind these plants had recently told the company that it was canceling its drilling plans in the area. Therefore, as there is no apparent offset to continued declines in the cash flows, we determined that the intangible assets had been impaired.
(Profit) Loss on Energy Trading Contracts. The profit on energy trading contracts was $2.9 million for the nine months ended September 30, 2002 compared to $1.5 million for the nine months ended September 30, 2001, an increase of $1.4 million. Substantially all of the gain in the 2001 period relates to realized margins on delivered volumes in the producer services "off-system" gas marketing operations. In the 2002 period, the realized margins from the producer services operations, excluding the Enron contracts, were approximately $2.0 million.
The unrealized gains in 2002 were $4.3 million, due to the increase in natural gas prices from December 31, 2001 to September 30, 2002, from approximately $2.55 per MMBtu for the current month at December 31, 2001 to approximately $3.31 per MMBtu for the current month at the end of the period. Our predecessor recorded a loss of $5.7 million in the fourth quarter of 2001 related to the mark-to-market adjustments for Enron positions and corresponding purchase commitment contracts from a producer. Our predecessor purchased put options and sold call options in order to mitigate the risk of future price decreases on a portion of this fixed price purchase commitment. Due to an increase in prices from December 31, 2001, our predecessor recorded a mark-to-market gain in the first nine months of 2002 related to the fixed price purchase commitment contracts. During the nine months
52
ended September 30, 2002, our predecessor realized losses of $3.4 million relating to the fixed price purchase commitment for settled contracts. Unrealized losses for these positions had been recorded at December 31, 2001. Accordingly, the previously recorded losses on settled contracts were reversed in the nine months ended September 30, 2002. See "—Year Ended December 31, 2001 Compared to Year Ended December 31, 2000—(Profit) Loss on Energy Trading Contracts."
The receivable from Enron will not be contributed to our new partnership.
Depreciation and Amortization. Depreciation and amortization expenses were $6.0 million for the nine months ended September 30, 2002 compared to $4.2 million for the nine months ended September 30, 2001, an increase of $1.9 million, or 44%. The increase is primarily related to additional depreciation expense associated with the CCNG assets purchased in May 2001.
Interest Expense. Interest expense was $2.4 million for the nine months ended September 30, 2002 compared to $1.5 million for the nine months ended September 30, 2001, an increase of $0.9 million, or 56%. The increase relates primarily to bank debt incurred in the acquisitions of the CCNG assets in May 2001, and indebtedness incurred in acquisition of various treating plants during 2001.
Net Income (Loss). Net income (loss) for the nine months ended September 30, 2002 was $1.5 million, compared to $2.6 million for the nine months ended September 30, 2001, a decrease of $1.2 million. Gross margin increased by $8.0 million from the first nine months of 2001 to the first nine months of 2002, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, and interest expense as discussed above. Non-cash charges for depreciation and amortization and for impairment expense also increased, partially offset by the gain on energy trading activities.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Revenues. Midstream revenues were $362.7 million for the year ended December 31, 2001 compared to $91.6 million for the year ended December 31, 2000, an increase of $271.1 million, or 296%. Revenues were higher in 2001 primarily due to:
The remaining increase in Midstream revenue is primarily attributable to the average price of natural gas in 2001 being approximately $0.39 per MMBtu higher than the average price in 2000.
Revenues for natural gas treating were $24.4 million in 2001 compared to $23.3 million in 2000, an increase of $1.0 million, or 4%, due to new plants placed in service.
53
Purchased Gas Costs. Midstream division purchased gas costs for the year ended December 31, 2001 were $344.8 million compared to $86.4 million for the prior year, an increase of $258.3 million, or 299%. Costs were higher in 2001 primarily due to:
Treating division purchased gas costs were $18.1 million in 2001 compared to $19.6 million in 2000, a decrease of $1.5 million, or 8%. In combination with the improvement in revenues in natural gas treating, the decrease in costs resulted in an improvement in gross margin of $2.5 million, or 68%. This improvement is primarily attributable to new plants placed in service for a fee, as opposed to purchase and resale of the gas.
Operating Expenses. Operating expenses were $7.4 million for the year ended December 31, 2001, compared to $2.3 million for the year ended December 31, 2000, an increase of $5.1 million, or 218%. Expenses were higher in 2001 than in 2000 primarily due to:
General and Administrative Expenses. General and administrative expenses were $5.9 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.1 million, or 110%. The increase in general and administrative expense is associated with the increase in employees caused by our rapid growth and preparation for our initial public offering. Total personnel employed increased from 44 to 107 between the end of 2000 and the end of 2001.
Stock Based Compensation. Stock based compensation expense was zero in 2001 compared to $8.8 million for the year ended December 31, 2000. The stock based compensation in 2000 is a charge associated with the valuation of management's interest in our predecessor as a result of the Yorktown investment in May 2000.
Impairments. Impairment expense was $2.9 million for the year ended December 31, 2001 compared to zero for the prior year. The impairment charge was recorded to reduce the carrying value
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of the Jonesville plant and related intangible assets to fair value in accordance with SFAS 121. See "—Critical Accounting Policies—Impairment of Long-Lived Assets" below.
(Profit) Loss on Energy Trading Contracts. The loss on energy trading contracts for the year ended December 31, 2001 was $3.7 million compared to a profit of $1.9 million for the prior year. The loss on energy trading contracts in 2001 includes $5.7 million associated with the write-down of the estimated realizable value of our receivable from Enron North America Corp., a subsidiary of Enron Corp., at December 31, 2001. On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp., each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Enron North America 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, 2001. Additionally, we had entered into natural gas hedging and physical delivery contracts with Enron North America. According to the terms of the contracts, Enron North America is liable to us for the mark-to-market value of all contracts outstanding on the date we exercised our termination right under the contracts, which totaled approximately $4.6 million and which has been recorded as a receivable from Enron North America. We have accounted for these contracts as energy trading contracts whereby changes in fair value of the fixed price purchase commitments are recognized in earnings.
We had offsets to the above amounts totaling approximately $0.3 million, resulting in a net $8.2 million receivable from Enron North America at December 31, 2001. Due to the uncertainty of future collections, a charge and related allowance for 70% of the net receivable, or $5.7 million, was recorded at December 31, 2001. Further adjustments to the Enron receivable will be recognized in earnings when management believes recovery of the asset is assured or additional reserves are warranted.
The receivable from Enron will not be contributed to our new partnership.
Partially offsetting the Enron-related loss in the 2001 period are the realized margins on delivered volumes in the producer services "off-system" gas marketing operations. In 2001, the realized margins from the producer services operations were approximately $1.9 million, compared to approximately $1.8 million in 2000.
Depreciation and Amortization. Depreciation and amortization expense was $6.1 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000, an increase of $3.3 million, or 119%. The increase in depreciation and amortization is primarily related to acquisitions of new assets, which resulted in additional depreciation and amortization expense as follows:
In addition, the accounting associated with the Yorktown investment in May 2000 resulted in an increase in depreciation and amortization for subsequent periods. Therefore, depreciation and amortization expense for the first four months of 2000 is approximately $0.4 million lower than if the investment had occurred at the beginning of 2000.
Interest Expense. Interest expense was $2.3 million for the year ended December 31, 2001 compared to $0.6 million for the year ended December 31, 2000, an increase of $1.6 million, or 270%. The increase was principally caused by increases in average outstanding borrowings as a result of the
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CCNG acquisition and the acquisition and refurbishment of treating plants. In addition, borrowings relative to the Arkoma and Gulf Coast assets were outstanding for the full year in 2001 as compared to only a part of 2000.
Net Income (Loss). Net loss for the year ended December 31, 2001 was ($3.9) million compared to ($6.1) million for the year ended December 31, 2000. Gross margin improved from $8.9 million in 2000 to $24.2 million in 2001, an improvement of $15.3 million, or 171%, largely as a result of acquisition-related growth as discussed above. This improvement was partially offset by increases in recurring cash charges for operating expenses, general and administrative expenses, and interest expense totaling $9.8 million, non-cash charges for depreciation and amortization of $3.3 million, and the loss on energy trading contracts and impairments totaling $8.5 million.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Revenues. Midstream revenues were $91.6 million for the year ended December 31, 2000 compared to $7.9 million for the year ended December 31, 1999, an increase of $83.7 million. This increase is attributable to the Arkoma assets being included in the last five months of 2000, adding approximately $7.3 million in revenues, and the Gulf Coast assets being included in the last four months of 2000, adding approximately $76.5 million to revenues.
Revenues for natural gas treating were $23.3 million for the year ended December 31, 2000 compared to $9.8 million for the year ended December 31, 1999, an increase of $13.6 million, or 139%. Of this increase, approximately $6.8 million is due to increases in the price of natural gas from 1999 to 2000 as discussed above, and approximately $5.4 million is due to volume increases in plants in service both years. The balance of the increase is due to new plants placed in service in 2000.
Purchased Gas Costs. Midstream purchased gas costs were $86.4 million for the year ended December 31, 2000 compared to $5.2 million for the year ended December 31, 1999, an increase of $81.3 million. This increase is attributable to the Arkoma assets being included in the last five months of 2000, adding approximately $6.1 million to purchased gas costs, and the Gulf Coast assets being included in the last four months of 2000, adding approximately $74.7 million to purchased gas costs.
Treating division purchased gas costs were $19.6 million for the year ended December 31, 2000 compared to $8.1 million for the year ended December 31, 1999, an increase of $11.5 million, or 142%. Of this increase, approximately $5.7 million is due to increases in the price of gas as discussed above. Approximately $4.7 million is associated with volume increases at treating plants in service during both years. The balance of the increase is due to new plants placed in service in 2000.
Operating Expenses. Operating expenses were $2.3 million for the year ended December 31, 2000 compared to $1.0 million for the year ended December 31, 1999, an increase of $1.4 million, or 137%. The increase is primarily attributable to operating costs of approximately $0.7 million related to the Arkoma and the Gulf Coast assets acquired during 2000, and an increase during 2000 in the number of operated treating plants from three in 1999 to eight in 2000, which increased operating costs by approximately $0.7 million.
General and Administrative Expenses. General and administrative expenses were $2.8 million for the year ended December 31, 2000 compared to $2.1 million for the year ended December 31, 1999, an increase of $0.7 million, or 36%. General and administrative expenses increased primarily in support of the acquisitions of the Gulf Coast and Arkoma assets and the increase in the number of treating plants in service.
Stock Based Compensation. Stock based compensation expense was $8.8 million for the year ended December 31, 2000 compared to zero in the prior year. The stock based compensation in 2000 is
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a charge associated with the valuation of management's interest in our predecessor as a result of the Yorktown investment in May 2000.
Impairments. Impairment expense of $0.5 million in 1999 is associated with Treating division membrane equipment.
(Profit) Loss on Energy Trading Contracts. The gain was $1.9 million for the year ended December 31, 2000 compared to $1.8 million for the year ended December 31, 1999. Substantially all the profit in both periods was due to realized margins on delivered gas in the producer services "off system" gas marketing operations.
Depreciation and Amortization. Depreciation and amortization expense was $2.8 million for the year ended December 31, 2000 compared to $1.3 million for the year ended December 31, 1999, an increase of $1.5 million, or 116%. Depreciation and amortization increased for the year ended December 31, 2000 by $0.5 million as a result of the acquisitions of the Gulf Coast system and Arkoma gathering system in 2000, and by $0.3 million as a result of the increase in the number of treating plants in operation.
In addition, the accounting associated with the Yorktown investment in May, 2000 resulted in an increase in depreciation and amortization for subsequent periods. Therefore, depreciation and amortization expense for the last eight months of 2000 are $0.8 million higher than if the investment had occurred at the end of 2000.
Other Income (Expense). Other income of $0.5 million in the year ended December 31, 2000 is primarily associated with adjustments of realized values to actual on prior-period sales transactions. Other expense in the year ended December 31, 1999 is primarily associated with a loss on the sale of a piece of equipment.
Net Income (Loss). Net loss for the year ended December 31, 2000 was $6.1 million compared to net income of $0.5 million for the year ended December 31, 1999. Gross margin improved from $4.4 million to $8.9 million, an improvement of $4.5 million, as a result of higher margins on gas purchased and resold due to the higher gas prices in 2000, increased treating volume and the Arkoma and Gulf Coast acquisitions. This improvement was partially offset by increases in recurring cash charges for operating expenses and general and administrative expenses totaling $2.1 million and non-cash charges for depreciation and amortization of $1.5 million. Stock-based compensation expense of $8.8 million offset the net effect of the improvements in operating results year-over-year, creating the net loss.
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.
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We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, oil and natural gas liquids. We also manage our 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 our future commitments and significantly reduce our risk to the movement in natural gas prices.
Prior to January 1, 2001, financial instruments which qualified for hedge accounting were accounted for using the deferral method of accounting, whereby unrealized gains and losses were generally not recognized until the physical delivery required by the contracts was made.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. In accordance with SFAS No. 133, all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
We conduct "off-system" gas marketing operations as a service to producers on systems that we do not own. We refer to these activities as part of producer services. In some cases, we earn an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, we purchase the natural gas from the producer and enter into a sales contract with another party to sell the natural gas. Where we take 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.
We manage our 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 our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for our 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 requires energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.
For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In accordance with EITF 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts, we have reported the results of our producer services business on a net basis. Accordingly, (profit) loss on energy trading activities includes both realized gains and losses on settled transactions, and mark-to-market adjustments to the fair value of derivative and physical delivery contracts.
We are subject to counterparty credit risk on both financial and physical delivery contracts. We attempt to manage our credit risk through diversification of our counterparties as well as our credit policies. During 2001, we recorded a charge of approximately $5.7 million related to the deterioration in creditworthiness of Enron. This charge was 70% of the receivable from Enron at December 31, 2001.
Impairment of Long-Lived Assets. In accordance with Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, we evaluate the long-lived assets, including related intangibles, of identifiable business
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activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Liquidity and Capital Resources
Cash Flows. Net cash provided by operating activities was $15.1 million and $10.4 million for the nine months ended September 30, 2002 and 2001, respectively, an increase of $4.7 million. Net cash provided by operating activities increased during the nine months ended September 30, 2002 principally due to higher margins ($8.0 million), offset by higher cash operating expenses ($2.7 million).
Net cash used in operating activities was $8.3 million for the year ended December 31, 2001. Net cash provided by operating activities was $15.1 million and $1.4 million for the years ended December 31, 2000 and 1999, respectively. Net cash used in operating activities during the year ended December 31, 2001 was $23.4 million lower than the prior year principally attributable to higher margins ($15.3 million), offset by higher cash expenses ($9.8 million), the loss on energy trading contracts related to Enron ($5.7 million), and the impact of the decline in natural gas prices during 2001 on our accounts payable, accrued liabilities and accounts receivable. We collect our receivables in the month before paying for our gas purchases, which created a $23.7 million relative decline in cash provided by operations. As gas prices were higher at the end of 2000 than at the end of 2001, and since we had already collected a greater portion of our receivables at that point than we had paid for our purchases, the subsequent funding of our payables for the higher-priced gas creates a use of cash. We had a working capital deficit of $2.3 million and $8.6 million at December 31, 2001 and September 30, 2002, respectively. The working capital deficit is primarily due to timing differences related to paying for gas purchases and the collection of our receivables.
Although net income was lower in 2000 than in 1999, cash provided by operations was higher in 2000 principally due to stock based compensation, as $8.0 million of the $8.8 million charge was a
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non-cash impact. Higher margins ($4.5 million) and higher contribution from working capital accounts ($11.5 million) were partially offset by higher cash expenses ($2.4 million).
Net cash used in investing activities was $12.7 million and $47.3 million for the nine months ended September 30, 2002 and 2001, respectively. Net cash used in investing activities during both periods was primarily related to acquisition and internal growth projects, including the CCNG acquisition in 2001. Net cash used in investing activities was $52.5 million, $28.5 million and $1.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. Net cash used in investing activities during each of the years ended December 31, 2001, 2000 and 1999 was primarily to fund acquisitions of the CCNG assets, buying and refurbishing and installing treating plants, the Arkoma and Gulf Coast systems, the Millenium acquisition, and internal growth capital projects.
Net cash provided by (used in) financing activities was $(2.8) million and $32.2 million for the nine months ended September 30, 2002 and 2001, respectively. Net cash provided by financing activities was $42.6 million and $36.8 million for the years ended December 31, 2001 and 2000, respectively. Net cash used in financing activities was $0.9 million for the year ended December 31, 1999. Financing activities primarily represent equity investments and borrowings from banks to fund our acquisitions and other investments discussed above, and funding or refunding of the company's working capital needs.
Capital Requirements. The natural gas gathering, transmission, treating and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:
Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We have entered into an asset purchase agreement with Acacia Gas Corporation, an indirect subsidiary of Devon Energy Corporation, to acquire approximately 200 miles of gathering pipeline located near our Gulf Coast system for a purchase price of $12.0 million. We expect to close this acquisition before the end of 2002 and to fund this acquisition through borrowings under our revolving credit facility discussed below. In addition, we are currently studying the possibility of expanding the capacity of our Gregory processing plant by 70,000 Mcf/d at an estimated cost ranging from $7.1 million to $9.2 million. For fiscal 2002, budgeted maintenance capital expenditures are approximately $2.0 million.
We believe that cash generated from operations will be sufficient to meet our minimum quarterly distributions and anticipated maintenance capital expenditures through September 30, 2003. We expect to fund our growth capital expenditures from cash provided by operations and, to the extent necessary, from the proceeds of borrowings under the revolving credit facility discussed below and the issuance of additional common units. We may not be able to issue additional units or may not be able to issue such units on favorable terms primarily as a result of market conditions for our securities. Our ability to pay distributions to our unitholders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.
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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2001, is as follows:
| Year |
Bank Debt |
Leases |
Total |
||||||
|---|---|---|---|---|---|---|---|---|---|
| |
(in millions) |
||||||||
| 2002 | — | $ | 1.2 | $ | 1.2 | ||||
| 2003 | — | 1.2 | 1.2 | ||||||
| 2004 | $ | 6.0 | 1.2 | 7.2 | |||||
| 2005 | 12.0 | 1.0 | 13.0 | ||||||
| 2006 | 12.0 | 1.0 | 13.0 | ||||||
Thereafter upon the closing of the offering, the proceeds of the offering will be used to retire a portion of the bank debt scheduled above, and the remainder will be refinanced with a new credit facility as discussed below.
Description of Credit Facility
In connection with the closing of this offering, we expect to enter into a new $67.5 million credit facility, consisting of the following two facilities:
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. We expect to have $10.3 million outstanding under the acquisition facility at the closing of the offering, leaving approximately $37.2 million available for future borrowings. The acquisition facility will convert into a term loan on April 30, 2004, and we will be required to make eleven quarterly payments equal to five percent of the outstanding borrowings. The first such payment will be due in July 2004. The term loan will mature in April 2007, at which time it will terminate and all outstanding amounts shall be due and payable. Prior to April 30, 2004, amounts borrowed and repaid under the acquisition credit facility may be reborrowed.
The working capital facility will be used for ongoing working capital needs, letters of credit, distributions and general partnership purposes, including future acquisitions and expansions. We expect to have $15.0 million of letters of credit issued under the working capital facility at the closing of the offering, leaving approximately $5.0 million available for future issuances of letters of credit, or up to $5.0 million of cash borrowings. The aggregate amount of borrowings under the working capital 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 $5.0 million sublimit for cash borrowings. This facility will mature in April 2004, 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 reborrowed. We will be required to reduce all working capital borrowings to zero for a period of at least 15 consecutive days once each year.
Our obligations under the credit facility will be 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. The credit facility will be 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).
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Indebtedness under the acquisition facility and the working capital facility will bear interest at our option at the administrative agent's reference rate plus 0.125% to 1.375% or LIBOR plus 1.625% to 2.875%. The applicable margin will vary 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. If our new credit facility had been in place at September 30, 2002, our weighted average interest rate would have been 3.9%. We will incur quarterly commitment fees based on the unused amount of the credit facilities.
The credit agreement will prohibit us 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, we expect that the credit facility will contain various covenants limiting our operating partnership's ability to:
We expect that the credit facility will also contain covenants requiring us to maintain:
Each of the following will be an event of default under the credit facility:
The credit facility is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 1999, 2000 or 2001 or the nine
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months ended September 30, 2002. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see "Business—Environmental Matters."
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations, requiring business combinations entered into after June 30, 2001, to be accounted for using the purchase method of accounting. Specifically identifiable intangible assets acquired, other than goodwill, will be amortized over their estimated useful economic life. This pronouncement had no effect on our predecessor's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS No. 142 requires that we identify reporting units for purposes of assessing potential future impairments of goodwill, reassess the useful lives of other existing recognized intangible assets, and cease amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with the guidance in SFAS No. 142. This statement is required to be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS No. 142 requires us to complete a transitional goodwill impairment test within six months from the date of adoption and reassess the useful lives of other intangible assets within the first interim quarter after adoption. Our predecessor had $4,873,000 recorded for goodwill, net of accumulated amortization at December 31, 2001 and recorded goodwill amortization expense of $292,000 for the year ended December 31, 2001. The only impact of adopting SFAS No. 142 on our financial statements was the discontinuance of the amortization of goodwill.
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 is required to be adopted by us beginning on January 1, 2003. At present, we are currently assessing but have not yet determined the complete impact the adoption of SFAS No. 143 will have on our financial position and results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 addresses financial accounting and reporting for impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to be Disposed Of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. This statement also amends ARB No. 51, Consolidated Financial Statements, to eliminate the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. See the impact of the
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adoption of SFAS No. 144 at Note 2 (c) of the Notes to Consolidated Financial Statements of our predecessor.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than when the entity commits to an exit plan. This standard is effective for all exit or disposal activities which are initiated after December 31, 2002. We do not anticipate that the adoption of SFAS No. 146 will have any impact on our financial position or results of operations.
In June 2002, the Emerging Issues Task Force ("EITF") reached consensus on certain issues in EITF Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts. Consensus was reached on two issues: (1) that gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the statement of operations, and (2) that entities should disclose the types of contracts that are accounted for as energy trading contracts along with a variety of other data regarding values, sensitivity to changes in estimates, maturity dates and other factors. We are required to implement this consensus in the third quarter of 2002. We have decided to implement this consensus as of June 30, 2002, and all comparitive financial statements have been restated to conform to this consensus. In October 2002, the EITF reached a consensus to rescind EITF 98-10. Accordingly, energy related contracts that are not accounted for pursuant to SFAS No. 133 should be accounted for as executory contracts and carried on an accrual basis, not fair value. The consensus should be applied prospectively to all new energy trading contracts entered into after October 25, 2002 and to all contracts that existed on October 25, 2002, in periods beginning after December 15, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principle. We have not determined the impact, if any, that the rescission of EITF 98-10 will have on our financial position or results of operations.
Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas we sell; and for the portion of the natural gas we process and for which we have taken the processing risk, we are at risk for the difference in the value of the NGL products we produce versus the value of the gas used in fuel and shrinkage in their production. We also incur credit risks and risks related to interest rate variations.
Commodity Price Risk. Approximately 6.5% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 46% of the gas we purchased during the nine months ended September 30, 2002. As a result, our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the nine months ended September 30, 2002, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have changed our processing margin by $341,600. Changes in natural gas prices indirectly may impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.
Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas using NYMEX futures or over-the-counter
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derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee. Hedges to protect our processing margins are generally for a more limited time frame than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas. Such hedges generally involve taking a short position with regard to the relevant liquids and an offsetting short position in the required volume of natural gas.
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform, as happened in the case of the Enron loss discussed above. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.
We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for certain of our 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 requires energy-trading contracts to be recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.
For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts are also recorded in profit or loss on energy trading contracts.
Credit Risk. We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of gas exposes us 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 our overall profitability.
Interest Rate Risk. We will be exposed to changes in interest rates, primarily as a result of our anticipated long-term debt with floating interest rates. We expect to have $11.1 million of indebtedness outstanding at the closing of this offering. We may make use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, although no such agreements are currently in place. The impact of a 1% increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $0.1 million. This amount has been determined by considering the impact of the hypothetical interest rates on our expected debt immediately after the offering of units to the public.
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We are a rapidly growing independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas. We connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities to ensure that it meets pipeline quality specifications, process natural gas for the removal of natural gas liquids or NGLs, transport natural gas and ultimately provide an aggregated supply of natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipelines and thereby generate gross margins based on the difference between the purchase and resale prices. In addition, we purchase natural gas from producers not connected to our gathering system for resale and sell natural gas on behalf of producers for a fee.
Our major assets include over 1,500 miles of natural gas gathering and transmission pipelines, one natural gas processing plant connected to our gathering system with a total NGL production capacity of 210,000 gallons per day and 49 natural gas treating plants. Our gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plant removes NGLs from a natural gas stream and fractionates, or separates, the NGLs into separate NGL products, including ethane, propane, mixed butanes and natural gasoline. Our natural gas treating plants, located largely in the Texas Gulf Coast area, remove impurities from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications.
We have grown rapidly since the inception of our various predecessors in 1992 through a combination of acquisitions and the construction of new assets. Our income before income taxes plus depreciation and amortization expense and interest expense, which we refer to as EBITDA, has increased from $0.5 million in 1997 to $4.4 million in 2001. Our EBITDA was $9.9 million for the nine months ended September 30, 2002. Our net loss was $3.9 million for the year ended December 31, 2001, and net income was $1.5 million for the nine months ended September 30, 2002. Net income and EBITDA for the year ended December 31, 2001 and the nine months ended September 30, 2002 has been reduced by non-cash impairment charges of $2.9 million and $3.2 million, respectively. Set forth in the table below is a list of our acquisitions since January 2000.
| Acquisition |
Acquisition Date |
Purchase Price (in thousands) |
Asset Type |
Average Throughput at Time of Acquisition (MMBtu/d) |
Average Throughput for Nine Months Ended September 30, 2002 (MMBtu/d) |
||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Provident City Plant | February 2000 | $ | 350 | Treating plants | 3,000 | 30,198 | |||||
| Will-O-Mills | February 2000 | 2,000 | Treating plants | 11,800 | 11,922 | ||||||
| Arkoma Gathering System | September 2000 | 10,500 | Gathering pipeline | 12,000 | 10,889 | ||||||
| Gulf Coast System | September 2000 | 10,632 | Gathering and transmission pipeline | 117,000 | 106,375 | ||||||
| CCNG acquisition | May 2001 | 30,003 | Gathering and transmission pipeline and processing plant | 271,900 | 261,764 | ||||||
| Pettus Gathering System | June 2001 | 450 | Gathering system | — | — | ||||||
| Millenium Gas Services | October 2001 | 2,124 | Treating assets | — | — | ||||||
| Florida Gas Transmission | June 2002 | 2,300 | Pipeline segment | — | — | ||||||
| Star Field Services | June 2002 | 2,000 | Gathering pipeline | 17,000 | 6,889 | ||||||
| KCS McCaskill Pipeline | June 2002 | 250 | Pipeline segment | — | — | ||||||
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We have two operating divisions, the Midstream division, which consists of our natural gas gathering, transmission, processing, marketing and producer services operations, and the Treating division, which provides natural gas treating for the removal of carbon dioxide and other contaminants.
Midstream Division. Our primary Midstream assets are four major systems along the Texas Gulf Coast and one in eastern Oklahoma, which in the aggregate consist of approximately 1,500 miles of gathering and transmission pipelines, and a natural gas processing plant connected to one of these gathering systems. For the nine months ended September 30, 2002, we gathered and transported approximately 368,681 Mcf/d of natural gas. Certain information regarding our primary assets in our Midstream division is summarized in the table below:
| |
|
|
|
Nine Months Ended September 30, 2002 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Asset |
Type |
Length (miles) |
Throughput Capacity (Mcf/d) |
Average Throughput (Mcf/d) |
Utilization of Capacity |
|||||||
| Gulf Coast system | Gathering and transmission pipelines | 484 | 200,000 | 101,021 | 50.5 | % | ||||||
| Corpus Christi system | Gathering and transmission pipelines | 295 | 350,000 | 154,364 | 44.1 | % | ||||||
| Gregory gathering system (1) | Gathering pipelines | 297 | 200,000 | 94,391 | 47.2 | % | ||||||
| Gregory processing plant | Processing and fractionation facility | N/A | 80,000 | 75,798 | 94.7 | % | ||||||
| Arkoma gathering system | Gathering pipelines | 100 | 20,000 | 10,177 | 50.9 | % | ||||||
| Other systems | Gathering and transmission pipelines | 330 | 319,400 | 61,362 | 19.2 | % | ||||||
| Total | 1,506 | |||||||||||
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In our producer services operations, we purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 80 independent producers. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer. In a recent survey by Mastio & Co., we were ranked first in satisfaction among producers. According to the survey, producers rated buyers on 25 attributes, including creditworthiness, promptness of payment, willingness to solve problems, accessibility, responsiveness, experience, and price competitiveness.
Treating Division. As of September 30, 2002, we owned 49 mobile, skid-mounted treating plants of various sizes, 23 of which were operated by our personnel, six of which were operated by producers, one of which was operated by a joint venture partner and 19 of which were held in inventory. The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications.
We believe that we are well positioned to compete in the natural gas gathering, transmission, treating, processing and producer services businesses. Our competitive strengths include:
Our treating operations, with 19 treating plants of varying sizes available in inventory, provides us with an advantageous position to compete for new treating business in the Texas Gulf Coast because natural gas produced from certain deeper formations in the Texas Gulf Coast is high in carbon dioxide. We believe our inventory of available treating plants gives us a competitive advantage for new treating business since we can often have a plant in service quicker than our competitors.
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Our strategy is to increase distributable cash flow per unit by improving the profitability of our existing systems through increasing volumes and reducing costs, focusing on accretive acquisitions and pursuing system construction and expansion opportunities. Our strategy is based on our expectation of
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a continued high level of drilling in our principal geographic areas and a process of ongoing divestitures of gas processing and transportation assets by large industry participants. We believe these two factors should present opportunities for continued expansion in our existing areas of operation as well as opportunities to acquire assets in new geographic areas that may serve as a platform for future growth. Key elements of our strategy include the following:
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The following diagram illustrates the natural gas treating, gathering, processing, fractionation and transmission process.
The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use markets. The midstream natural gas industry in North America includes approximately 525 processing plants that process approximately 50 Bcf per day of natural gas and produce approximately 80 million gallons per day of NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
Overview. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to increase by over 2% per annum, on average, to 35.0 Tcf by 2020, from an estimated 22.8 Tcf consumed in 2000, representing approximately 24% of all total end-user energy requirements by 2020. During the last six years, the United States has on average consumed approximately 19.8 Tcf per year, with average marketed domestic production of approximately 20.0 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.
Petroleum refining and chemicals manufacturing are significant components of the Texas industrial economy. According to the EIA, during each of the last six years, Texas has consumed approximately 3.6 Tcf per year, with average marketed production of approximately 5.3 Tcf per year during the same period. The supply of natural gas in Texas is an inducement for companies to expand or move their manufacturing facilities to Texas. It is also a benefit to electricity companies seeking to build natural gas driven power plants. The Texas Business and Economic Development Center reports that since January 1990, Texas has been the only state in the United States to add over 100,000 manufacturing jobs and that Texas currently ranks as the second largest manufacturing state in the country.
Natural gas reserves and production. As of December 31, 2000, operators in the United States had 177.4 Tcf of proved "dry" natural gas reserves and 186.5 Tcf of proved reserves of "wet" natural gas reserves. Natural gas is described as dry or wet depending on its content of heavy components. These are relative terms, but as generally used, a wet gas may contain five or six gallons or more of NGLs per Mcf, whereas a dry gas usually contains less than one gallon of recoverable liquids per Mcf. Texas accounted for approximately 42.1 Tcf, or 24%, of the proved dry gas reserves and 45.4 Tcf, or 24%, of proved wet gas reserves in the United States as of December 31, 2000. While gas production in the lower 48 states is projected to grow by 9.2 Tcf between 2000 to 2020, Texas, Louisiana and Oklahoma are projected to have the largest growth (3.2 Tcf) in production during this period.
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Natural gas gathering and treating. The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.
Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide. Treating plants are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems to ensure that it meets pipeline quality specifications.
Natural gas processing and fractionation. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream, as well as the removal of contaminants.
NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutane is fractionated from mixed butane (a stream of normal butane and isobutane in solution) or refined from normal butane through the process of isomerization, principally for use to enhance the octane content of motor gasoline and in the production of MTBE. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient in synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.
NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. Fractionation takes advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off to the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated, and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components: ethane, propane, isobutane, normal butane and natural gasoline. Since the fractionation process uses large quantities of heat, energy costs are a major component of the total cost of fractionation.
Natural gas transmission. Natural gas transmission pipelines receive natural gas from mainline transmission pipelines and gathering systems and deliver the processed natural gas to industrial end-users and utilities and to other pipelines.
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Substantially all of our margins are derived from the value we add by gathering and transporting natural gas, treating natural gas, processing natural gas, purchasing natural gas for resale and marketing natural gas. Our natural gas gathering, transmission, processing, marketing and producer services operations are conducted by our Midstream division, and our treating operations are conducted by our Treating division.
Midstream Division
Our natural gas gathering and transmission operations include over 1,500 miles of pipeline. We own a cryogenic gas processing facility with full liquid fractionation capabilities that is located on one of our major gathering systems north of Corpus Christi. For the nine months ended September 30, 2002, we gathered and transported approximately 368,681 Mcf/d of natural gas. Set forth below is a description of our principal pipeline systems.
![[nc_cad,157]Map showing Gulf Coast, Corpus Christi and Gregory systems[nc_cad,179]](g156887.jpg)
Gulf Coast System. The Gulf Coast system is an intrastate pipeline system consisting of approximately 484 miles of gathering and transmission pipelines with a mainline from Refugio County in south Texas running northeast along the Gulf Coast to the Brazos River in Fort Bend County near Houston. Our gathering and transmission pipeline ranges in diameter from four to 20 inches. We acquired the Gulf Coast system in September 2000 for a purchase price of approximately $10.6 million.
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The Gulf Coast system has two supply pipeline laterals which connect to gathering systems which collect natural gas from approximately 76 receipt points and five treating and processing plants operated by third parties. This system has three laterals—an eight inch lateral into the Victoria area, a 12 inch lateral into the Point Comfort area, and a 16 inch lateral into the Bay City area—which deliver natural gas directly to large industrial and utility consumers along the Gulf Coast. The system interconnects with multiple third-party pipelines through which we may purchase volumes not gathered through our systems for resale or through which we might deliver natural gas to customers which are not connected to our system. We also hold firm transportation capacity on the TXU Lone Star pipeline, which provides access for our Gulf Coast mainline system in Fort Bend County to the Katy hub, a major natural gas physical exchange that allows access to seven third-party pipelines, including Kinder Morgan, TECO and Trunkline. The Gulf Coast system has a capacity of 200,000 Mcf/d and average throughput on this system was approximately 101,021 Mcf/d for the nine months ended September 30, 2002.
We generate operating profits in our Gulf Coast system through the margins we earn by purchasing, gathering, transporting and reselling natural gas. We purchase natural gas from a producer, pipeline or marketing company and then transport and resell the gas. As of September 30, 2002, we were purchasing gas from over 60 producers primarily pursuant to month-to-month contracts and were reselling the natural gas to over 10 customers primarily pursuant to short-term or month-to-month arrangements. Beginning in July 2002, we started supplying natural gas to Entex under a two year contract. For the nine months ended September 30, 2002, approximately 92% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder were purchased at a percentage of an index, and all the natural gas volumes we sold were sold at a fixed price relative to an index.
On October 31, 2002, we entered into an asset purchase agreement with Acacia Gas Corporation, an indirect subsidiary of Devon Energy Corporation, to acquire approximately 200 miles of gathering pipeline located near our Gulf Coast system. The purchase price is $12.0 million and we expect to close the transaction before the end of 2002. The pipeline ranges in diameter from four to 14 inches and has a capacity of approximately 130,000 Mcf/d, with recent throughput of approximately 40,000 Mcf/d. Gathered natural gas currently flows to the Exxon Katy plant, which is scheduled to close in November 2003. We are examining delivering the natural gas from this gathering system to the Formosa Hydrocarbons processing plant at Point Comfort, Texas beginning in the spring of 2003.
Corpus Christi System. The Corpus Christi system is an intrastate pipeline system consisting of approximately 295 miles of gathering and transmission pipelines and extends from supply points in south Texas to markets in Corpus Christi, Texas. Our gathering and transmission pipelines range in diameter from four to 20 inches. We acquired the Corpus Christi system in May 2001 in conjunction with the acquisition of the Gregory gathering system and Gregory processing plant, which we collectively refer to as the CCNG Acquisition, for an aggregate purchase price of approximately $30 million. Based on the differences in how we operate and the prior owner operated the CCNG assets, the CCNG acquisition is not treated as an acquisition of a continuing business operation, but rather is accounted for as a purchase of assets. Prior to our acquisition, the CCNG assets were not treated as separate assets but part of a larger enterprise and very few transactions allocated to the CCNG systems were done on an arms-length basis with third parties and, accordingly, did not reflect market values. Since our acquisition, we have operated the assets as separate profit centers, with substantially all transactions done on an arms-length basis. As part of the CCNG acquisition, we entered into a contract whereby all of the processed natural gas coming from our Gregory processing plant is sold to a subsidiary of Kinder Morgan. This contract is described below under "—Gregory Processing Plant." After the completion of the acquisition, we hired 16 former employees of the seller, all of whom are in operational positions. Our Corpus Christi system had average throughput of approximately 152,000 MMBtu of gas per day at the time of our acquisition. The main lines comprising
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the Corpus Christi system were constructed in the 1940's with additional expansions throughout the 1990's. We believe the expected remaining life of the pipeline system is approximately 50 years.
Natural gas is supplied to the Corpus Christi system from approximately 13 receipt points, 12 treating and processing plants and third-party gathering systems and pipelines. The system interconnects with multiple third-party pipelines through which we may purchase volumes not gathered through our systems for resale or through which we may deliver natural gas to customers which are not connected to our system, including the Banquette hub. The Corpus Christi system has a capacity of 350,000 Mcf/d and average throughput on this system was approximately 154,364 Mcf/d for the nine months ended September 30, 2002.
We generate operating profits in our Corpus Christi system through the margins we earn by purchasing, gathering, transporting and reselling natural gas. As of September 30, 2002, we were purchasing natural gas from approximately 29 producers generally on month-to-month or short-term arrangements. For the nine months ended September 30, 2002, substantially all of the natural gas volumes we purchased were purchased at a fixed price relative to an index.
The Corpus Christi system transports natural gas to the Corpus Christi area where its customers include multiple major refineries and other industrial installations, as well as the local electric utility. As of September 30, 2002, we were selling gas to over 10 customers primarily pursuant to contracts that expire at various times between 2003 and 2006. For the nine months ended September 30, 2002, all of the natural gas volumes we sold were sold at a fixed price relative to an index. New customers added since the acquisition of this system have increased our sales volumes by 50,000 Mcf/d, replacing less profitable sales volumes that have been discontinued. Additionally, we have recently completed an agreement to provide transportation services to Calpine Energy Services, LP, the owner of a co-generation facility in Corpus Christi that is scheduled to come online in the fourth quarter of 2002. The Calpine facility is expected to add significantly to system demand under a 15 year contract that includes minimum annual payments to us in exchange for providing firm capacity of up to 100,000 MMBtu/d. This 500 megawatt co-generation facility will receive gas supply solely through two interconnections to the Corpus Christi transmission system. We expect average daily use by this facility to be approximately 70,000 MMBtu/d.
In June 2002, we acquired from Florida Gas Transmission approximately 70 miles of 20 inch transmission line which allows us access to the Florida Gas transmission mainline and accordingly the ability to reach markets in Florida. We are in the process of constructing an addition to this transmission line so we can create a connection between our Gulf Coast system and our Corpus Christi system. This connection will allow us to transport gas between our two systems and thereby reduce our dependence on third-party suppliers, move gas supplies to more favorable markets and enhance our margins.
Gregory Gathering System. We acquired the Gregory processing plant and the Gregory gathering system in May 2001 in connection with the acquisition of the Corpus Christi system. The plant and the gathering system are located north of Corpus Christi, Texas. The gathering system is connected to approximately 70 receipt points in San Patricio County, the Corpus Christi Bay area, Mustang Island, and adjacent coastal areas. The gathering system consists of approximately 297 miles of pipeline ranging in diameter from two inches to 18 inches with a total estimated throughput capacity of 200,000 Mcf/d. Until recently, all of the gas from the gathering system has been delivered to the inlet of the processing plant. Accordingly, the capacity of the gathering system was constrained by the inlet capacity of the plant, which is approximately 80,000 Mcf/d. We have modified the system to put a by-pass around the plant so that approximately 30,000 Mcf/d of gas can be delivered to the plant tailgate without processing in addition to volumes processed in the plant. The gathering system had average throughput of approximately 94,391 Mcf/d for the nine months ended September 30, 2002. Our Gregory gathering system had average throughput of approximately 76,500 MMBtu of gas per day at
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the time of our acquisition. The Gregory gathering system was constructed in the 1980's and we believe the expected remaining life of the pipeline system is approximately 50 years.
We generate operating profits in our Gregory gathering system and our Gregory processing plant through the margins earned by purchasing, gathering, transporting and reselling natural gas, and through the incremental margin, if any, generated by processing the portion of the gas for which we retain the processing risk. As of September 30, 2002, we were purchasing gas from over 40 producers primarily pursuant to month-to-month contracts, and for the nine months ended September 30, 2002, approximately 91% of the natural gas volumes we purchased were purchased at a fixed price relative to an index and the remainder were purchased at percentage of an index. All of the processed natural gas from our Gregory processing plant is sold to one customer pursuant to a contract expiring in 2006 at a price based on a fixed price relative to a monthly index. Liquids produced are sold under two contracts, one expiring in 2007, and the other expiring in March 2003.
Gregory Processing Plant. Our Gregory processing plant is a cryogenic turbo-expander with a 210,000 gallon per day fractionator that removes liquid hydrocarbons from the liquids-rich gas produced into the Gregory gathering system. Our Gregory processing plant has an inlet capacity of approximately 80,000 Mcf/d and average throughput was approximately 75,798 Mcf/d for the nine months ended September 30, 2002. At the time of our acquisition, the plant was processing approximately 43,400 MMBtu of gas per day. The Gregory processing plant was constructed in the 1980's and expanded and upgraded in 1998. We believe the expected remaining life of the Gregory processing plant is approximately 20 years.
In addition to the margins generated by the Gregory gathering system, we generate revenues at our Gregory processing plant under two types of arrangements:
Arkoma Gathering System. We acquired the Arkoma gathering system, located in the Southeastern region of Oklahoma, in September 2000 for $10.5 million. In addition, since acquiring this system, we have acquired the Shawnee extension, consisting of 15 miles of gathering pipelines extending through additional supply areas in this region. The Arkoma gathering system when acquired was approximately 84 miles in length and included a 3,700 horsepower compressor station. With the addition of the Shawnee extension and additional well connections, the system is now approximately 100 miles in length and ranges in diameter from two to 10 inches. This low-pressure system gathers gas from approximately 144 wells to three compressor stations for discharge to a mainline transmission pipeline.
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This system has a capacity of 20,000 Mcf/d and average throughout was approximately 10,177 Mcf/d for the nine months ended September 30, 2002.
We generate a margin for gathering and transporting gas in the Arkoma gathering system equal to a percentage of the proceeds from the sale of the natural gas into the mainline transmission pipeline. We take title to the gas at the metering point into the gathering system, with payment based upon an allocation of the metered volume sold into the mainline transmission facilities of our customer with the producer sharing their pro rata portion of the fuel costs for the compression and the removal of water from the natural gas stream.
Other Systems. We own several small gathering systems totaling approximately 105 miles, including our Manziel system in Wood County, Texas, our San Augustine system in San Augustine County, Texas, our Freestone Rusk system in Freestone County, Texas, and our Jack Starr and North Edna systems in Jackson County, Texas. Through Crosstex Pipeline Partners, a limited partnership of which we are the co-general partner, we own a 28% interest in five gathering systems in east Texas, totaling 64 miles with a combined capacity of 112 Mmcf/d. We also own five industrial bypass systems each of which supplies natural gas directly from a pipeline to a dedicated customer. The combined volumes for these five industrial bypass systems was approximately 4.4 Mmcf/d for the nine months ended September 30, 2002. In addition to these systems, we own various smaller gathering and transmission systems located in Texas and New Mexico.
Producer Services. We currently purchase for resale volumes of natural gas that do not move through our gathering, processing or transmission assets from over 80 independent producers. We engage in such activities on more than 30 interstate and intrastate pipelines with a major emphasis on Gulf Coast pipelines. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.
Our business strategy includes developing relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business also provides us with strategic insights and valuable market intelligence which may impact our expansion and acquisition strategy.
We offer to our customers the ability to hedge their purchase or sale price by agreeing to sell to us or to purchase from us volumes of natural gas. This risk management tool enables our customers to reduce pricing volatility associated with the sale and purchase of natural gas. When we agree to purchase or sell natural gas from a customer, we contemporaneously execute a contract for the sale or purchase of such natural gas, we enter into an offsetting obligation under futures contracts on the New York Mercantile Exchange or by using over-the-counter derivative instruments with third parties.
Treating Division
As of September 30, 2002, we owned 49 treating plants, 23 of which were operated by our personnel, six of which were operated by producers, one of which was operated by our joint venture partner, and 19 of which were held in inventory. We entered the treating business in 1998 with the strategic acquisition of WRA Gas Services. In October 2001, we completed our largest acquisition of gas treating assets with the acquisition of Millenium Gas Services, which added 11 treating plants, four of which were in operation and seven of which were placed in our inventory. With these two acquisitions and the acquisition of additional plants, we have one of the largest gas treating operations in the Texas Gulf Coast. The treating plants remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced to transportation systems to ensure that it meets pipeline quality specifications. Natural gas from certain formations in the Texas Gulf Coast is high in carbon dioxide.
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The majority of our active plants are treating gas from the Wilcox and Edwards formations, both of which are deeper formations that are high in carbon dioxide. Our active treating facilities include 27 amine plants, two hydrogen sulfide scavenger installations and one membrane plant. In cases where producers pay us to operate the treating facilities, we either charge a fixed rate per Mcf of natural gas treated or charge a fixed monthly fee.
In addition to our treating plants, we have three gathering systems with an aggregate of 43 miles of gathering pipeline located in Val Verde, Crockett, Dewitt and Live Oak counties, Texas that are connected to approximately 73 producing wells. These gathering systems are connected to three of our treating plants. The diameter of these gathering pipelines ranges from two to six inches. These gathering assets in the aggregate have a capacity of 65 Mmcf/d and average throughput was approximately 26 Mmcf/d for the nine months ended September 30, 2002. In cases where we both gather and treat natural gas, our fee is generally based on throughput.
A component of our strategy is to purchase used plants and then refurbish and repair them at our shop and seven-acre yard in Victoria, Texas and our 14-acre yard in Odessa, Texas. We believe that we can purchase used plants and recondition them at a significant cost savings to purchasing new plants. We have an inventory of plants of varying sizes which can be deployed after refurbishment. We also mount most of the plant equipment on skids allowing them to be moved in a timely and cost efficient manner. At such time as our active plants come offline, we will put them in our inventory pending redeployment. We believe our plant inventory gives us an advantage of several weeks in the time required to respond to a producer's request for treating services.
Treating process. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb the impurities from the gas. After mixing, gas and amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute. The size range of the 27 amine plants in operation is 3.5 to 300 gallons per minute, and the size range of the 19 plants in inventory is 3.5 to 1,000 gallons per minute.
Hydrogen sulfide scavenger facilities use a liquid or solid chemical that reacts with hydrogen sulfide thereby removing it from the gas. Used chemicals are disposed of and cannot be regenerated as amine can. The facilities are primarily vertical towers mounted on concrete foundations. As of September 30, 2002, we had two such facilities which were operated by the producer.
Membrane plants use a molecular filter to separate carbon dioxide and hydrogen sulfide from natural gas. As of September 30, 2002, we had one such facility which was operated by the producer and one plant in inventory.
It is our policy that as we purchase natural gas, we establish a margin by selling natural gas for physical delivery to third-party users, using over-the-counter derivative instruments or by entering into a future delivery obligation under futures contracts on the New York Mercantile Exchange. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes.
The natural gas gathering, transmission, treating, processing and marketing industries are highly competitive. We face strong competition in acquiring new natural gas supplies. Our competitors in
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obtaining additional gas supplies and in treating new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. The main difference between us and our competitors is that we offer most midstream services, while our competitors typically offer only a few select services. Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors in the Texas Gulf Coast area for natural gas supplies and markets include El Paso Field Services, Kinder Morgan Inc., Houston Pipeline Company and Duke Energy Field Services.
Our gas treating and processing operations face competition from manufacturers of new treating plants and from a small number of regional operators that provide plant leasing and operations similar to ours. We also face competition from vendors of used equipment that occasionally lease and operate plants for producers. Our primary competitor for natural gas treating services in our principal market area is The Hanover Company.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.
Our end-user pipelines have connections with major interstate and intrastate pipelines which we believe have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of our gathering systems, we evaluated well and reservoir data furnished by producers to determine the availability of natural gas supply for the systems. Based on those evaluations, we believe that there should be adequate natural gas supply to recoup our investment with an adequate rate of return. We do not routinely obtain independent evaluations of reserves dedicated to our systems due to the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such producing reserves.
Regulation by FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so FERC does not directly regulate any of our operations. However, FERC's regulation influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:
In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers
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matters such as pipelines' rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Intrastate Pipeline Regulation. Our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies of the states in which they are located. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.
Our operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates.
Our operations in New Mexico, where we own a private line that is used to serve one customer, are not regulated by the New Mexico Public Regulation Commission. Similarly, our eighty-four mile gathering line in Oklahoma is not regulated by the Oklahoma Corporation Commission. While it is possible that Oklahoma or New Mexico may try to assert jurisdiction on these lines, it is not likely that the assertion of that jurisdiction would have a significant effect on our operations in those states because both states tend to have light-handed regulation of natural gas pipeline facilities.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
We are subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing
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states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.
General. Our operation of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionization and storage of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to release of hazardous substances or wastes into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing, and operating our plants, pipelines, and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities.
Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays. While we believe that we currently hold material governmental approvals required to operate our major facilities, we are currently evaluating and updating permits for certain of our facilities that primarily were obtained in recent acquisitions. As part of the regular overall evaluation of our operations, we have implemented procedures and are presently working to ensure that all governmental approvals for both recently acquired facilities and existing operations are updated, as may be necessary. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or
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timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury or damage to property. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although "petroleum" as well as natural gas and NGLs are excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous state laws.
We also generate both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the Environmental Protection Agency, or EPA, has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related
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industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination.
Air Emissions. Our operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our processing and fractionating plants, pipelines, and storage facilities that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. Such requirements, if applicable to our operations, could cause us to incur capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of our facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.
Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.
Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
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Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While we have no reason to believe that we operate in any area that is currently designed as habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Safety Regulations. Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our results of operations or financial positions.
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our Gregory processing plant is on land that we own in fee.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. With respect to any consents, permits or authorizations that have not been obtained, our general partner believes that these consents, permits or authorizations will be obtained after the closing of this offering, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.
Our general partner believes that we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by affiliates of our predecessor until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. Our general partner believes that none of such encumbrances should materially detract from the value of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business.
In addition to our gathering and treating facilities discussed above, we occupy approximately 17,000 square feet of space at our executive offices in Dallas, Texas under a lease expiring in November 2004. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
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As of July 1, 2002, we had approximately 120 full-time employees. Approximately half of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.
We are not currently a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverage and deductibles as the managing general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
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Management of Crosstex Energy, L.P.
Crosstex Energy GP, LLC, as the general partner of our general partner, will manage our operations and activities on behalf of our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.
At least two members of the board of directors of Crosstex Energy GP, LLC will serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by the Nasdaq Stock Market. Additionally, the members of the conflicts committee are prohibited from holding any ownership interest in us or in any of our affiliates other than common units. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
Two members of the board of directors will also serve on a compensation committee, which will oversee compensation decisions for the officers of our general partner as well as the compensation plans described below. In addition, three members of the board of directors will serve on an audit committee that will review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The members of the audit committee must meet the independence standards established by the Nasdaq Stock Market.
Directors and Executive Officers of Crosstex Energy GP, LLC
The following table shows information for the directors and executive officers of Crosstex Energy GP, LLC. Executive officers and directors are elected for one-year terms.
| Name |
Age |
Position with Crosstex Energy GP, LLC |
||
|---|---|---|---|---|
| Barry E. Davis | 41 | President, Chief Executive Officer and Director | ||
| James R. Wales | 48 | Executive Vice President—Midstream Division | ||
| A. Chris Aulds | 40 | Executive Vice President—Treating Division | ||
| Jack M. Lafield | 51 | Senior Vice President—Business Development | ||
| William W. Davis | 49 | Senior Vice President and Chief Financial Officer | ||
| Michael P. Scott | 46 | Vice President—Engineering and Operations | ||
| C. Roland Haden | 62 | Director nominee | ||
| Bryan H. Lawrence | 60 | Director | ||
| Sheldon B. Lubar | 73 | Director nominee | ||
| Robert F. Murchison | 48 | Director nominee | ||
| Stephen A. Wells | 58 | Director nominee |
Within 90 days of the closing of this offering, Crosstex Energy GP, LLC expects to appoint another director who meets the independence standards established by the Nasdaq Stock Market.
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Barry E. Davis, President, Chief Executive Officer and Director, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of our predecessor. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis holds a B.B.A. in Finance from Texas Christian University.
James R. Wales, Executive Vice President—Midstream Division, joined our predecessor in December 1996. As one of the founders of Sunrise Energy Services, Inc., he helped build Sunrise into a major national independent natural gas marketing company, with sales and service volumes in excess of 600,000 MMBtu/d. Mr. Wales started his career as an engineer with Union Carbide. In 1981, he joined Producers Gas Company, a subsidiary of Lear Petroleum Corp., and served as manager of its Mid-Continent office. In 1986, he joined Sunrise as Executive Vice President of Supply, Marketing and Transportation. From 1993 to 1994, Mr. Wales was the Chief Operating Officer of Triumph Natural Gas, Inc., a private midstream business. Prior to joining Crosstex, Mr. Wales was Vice President for Teco Gas Marketing Company. Mr. Wales holds a B.S. degree in Civil Engineering from the University of Michigan, and a Law degree from South Texas College of Law.
A. Chris Aulds, Executive Vice President—Treating Division, together with Barry E. Davis, participated in the management buyout of Comstock Natural Gas in December 1996. Mr. Aulds joined Comstock Natural Gas, Inc. in October 1994 as a result of the acquisition by Comstock of the assets and operations of Victoria Gas Corporation. Mr. Aulds joined Victoria in 1990 as Vice President responsible for gas supply, marketing and new business development and was directly involved in the providing of risk management services to gas producers. Prior to joining Victoria, Mr. Aulds was employed by Mobil Oil Corporation as a production engineer before being transferred to Mobil's gas marketing division in 1989. There he assisted in the creation and implementation of Mobil's third-party gas supply business segment. Mr. Aulds holds a B.S. degree in Petroleum Engineering from Texas Tech University.
Jack M. Lafield, Senior Vice President—Business Development, joined our predecessor in August 2000. For five years prior to joining Crosstex, Mr. Lafield was Managing Director of Avia Energy, an energy consulting group, and was involved in all phases of acquiring, building, owning and operating midstream assets and natural gas reserves. He also provided project development and consulting in domestic and international energy projects to major industry and financing organizations, including development, engineering, financing, implementation and operations. Prior to consulting, Mr. Lafield held positions of President and Chief Executive Officer of Triumph Natural Gas, a private midstream business he founded, President and Chief Operating Officer of Nagasco, Inc. (a joint venture with Apache Corporation), President of Producers' Gas Company, and Senior Vice President of Lear Petroleum Corp. Mr. Lafield holds a B.S. degree in Chemical Engineering from Texas A&M University, and is a graduate of the Executive Program at Stanford University.
William W. Davis, Senior Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has 25 years of finance and accounting experience. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President—Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant. Mr. Davis is not related to Barry E. Davis.
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Michael P. Scott, Vice President—Engineering and Operations, joined our predecessor in July 2001. Before joining our predecessor, Mr. Scott held various positions at Aquila Gas Pipeline Corporation, including Director of Engineering from 1992 to 2001, Director of Operations from 1990 to 1992, and Director of Project Development from 1989 to 1990. Prior to Aquila, Mr. Scott held various project development and engineering positions at Cabot Corporation/Cabot Transmission, Perry Gas Processors and General Electric. Mr. Scott holds a B.S. degree in Mechanical Engineering from Oklahoma State University.
C. Roland Haden will join us as a director upon the completion of this offering. Mr. Haden held the positions of Vice Chancellor of the Texas A&M System, Director of the Texas Engineering Experiment Station and Dean of Look College of Engineering at Texas A&M University from 1993 to 2002. Prior to joining Texas A&M University, Mr. Haden served as Vice Chancellor for Academic Affairs and Provost of Louisiana State University from 1991 to 1993 and held various positions with Arizona State University, including Dean and Professor of Engineering & Applied Sciences from 1989 to 1991, Provost, ASU West Campus from 1988 to 1989, Vice President for Academic Affairs from 1987 to 1988 and Dean and Professor of Engineering and Applied Sciences from 1978 to 1987. Mr. Haden formerly served as a director of Square D Company, a Fortune 500 electrical manufacturing company, as a director of E-Systems, a Fortune 500 defense contractor, and as a member of the Telecommunications Advisory Board of A.T. Kearney, a nationally ranked consulting firm. He has been a director of Inter-tel, Inc., a leading telecommunications company, since 1983. Mr. Haden holds a bachelor's degree from the University of Texas, Arlington, a Masters degree from the California Institute of Technology, and a Ph.D. from the University of Texas, Austin, all in electrical engineering.
Bryan H. Lawrence joined our predecessor as a director in May 2000. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Carbon Energy Corporation, D&K Healthcare Resources, Inc., Hallador Petroleum Company, TransMontaigne Inc., and Vintage Petroleum, Inc. (each a United States publicly traded company) and Cavell Energy Corp. (a Canadian publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor Resources Inc., Camden Resources, Inc., ESI Energy Services Inc., Ellora Energy Inc., and Dernick Resources Inc. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.
Sheldon B. Lubar will join us as a director upon the completion of this offering. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar has also been a Director of C2, Inc., a logistics and manufacturing company, since 1995, MGIC Investment Corporation, a mortgage insurance company, since 1991, Grant Prideco, Inc., an energy services company, since 2000, and Weatherford International, Inc., an energy services company, since 1995. Mr. Lubar holds a bachelor's degree in Business Administration and a Law degree from the University of Wisconsin—Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin—Milwaukee.
Robert F. Murchison will join us as a director upon the completion of this offering. Mr. Murchison has been the President of the general partner of Murchison Capital Partners, L.P., a private equity investment partnership since 1992. Prior to founding Murchison Capital Partners, L.P., Mr. Murchison held various positions with Romacorp, Inc., the franchisor and operator of Tony Roma's restaurants, including Chief Executive Officer from 1984 to 1986 and Chairman of the board of directors from 1984
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to 1993. He served as a director of Cenergy Corporation, an oil and gas exploration and production company, from 1984 to 1987, Conquest Exploration Company from 1987 to 1991 and has served as a director of TNW Corporation, a short line railroad holding company, since 1981 and Tecon Corporation, a holding company with holdings in real estate development, investor owned water utilities, rail car repair and the fund of funds management business, since 1978. Mr. Murchison holds a bachelor's degree in history from Yale University.
Stephen A. Wells will join us as a director upon the completion of this offering. Mr. Wells has been the President of Wells Resources, Inc., a private oil, gas and ranching company since 1983. Prior to founding Wells Resources, Inc., Mr. Wells served in executive management positions with various energy companies, with an emphasis in oil field services. He served as Chief Executive Officer and director of Avista Resources, Inc. from April 1999 to October 1999, director and Chief Executive Officer of Grasso Corporation, a contract production management company, from 1992 to 1994, Chief Executive Officer and director of Coastwide Energy Services, Inc. from 1993 to 1996, and President, Chief Executive Officer and director of Wells Strathclyde Company, an oil field services company he co-founded from 1978 to 1982. Mr. Wells also serves as a director and audit committee chair of Oil States International and as a director and audit committee chair of Pogo Producing Company. Mr. Wells holds a bachelor's degree in accounting from Abilene Christian University.
Reimbursement of Expenses of the General Partner
Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the first 12 months following this offering, the amount which we will reimburse the general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf will not exceed $6.0 million. This reimbursement cap will not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on behalf of the partnership.
We, our general partner and its general partner, Crosstex Energy GP, LLC, were formed in July 2002. Accordingly, Crosstex Energy GP, LLC paid no compensation to its directors and officers with respect to the 2001 fiscal year. No obligations were accrued in respect of management incentive or retirement benefits for the directors and officers with respect to the 2001 fiscal year. Officers and employees of Crosstex Energy GP, LLC may participate in employee benefit plans and arrangements sponsored by Crosstex Energy GP, LLC, including plans which may be established by the general partner or its affiliates in the future.
No additional remuneration will be paid to officers or employees of Crosstex Energy GP, LLC who also serve as directors. Crosstex Energy GP, LLC anticipates that each independent director will receive a combination of cash and units as compensation for services rendered, including attending meetings of the board of directors and committee meetings. In addition, each independent director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.
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The executive officers of the general partner of our general partner, including Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, have entered into employment agreements to become effective upon the consummation of the offering of the common units. The following is a summary of the material provisions of those employment agreements, copies of which have been filed as exhibits to the registration statement relating to this prospectus. All of these employment agreements are substantially similar, with certain exceptions as set forth below.
Each of the employment agreements will have an initial term that expires two years from the effective date, but will automatically be extended such that the remaining term of the agreements will not be less than one year. The employment agreements provide for a base annual salary of $201,500, $171,064, $171,064, $160,875, $160,875 and $134,304 for Barry E. Davis, James R. Wales, A. Chris Aulds, Jack M. Lafield, William W. Davis and Michael P. Scott, respectively.
Except in the event of our becoming bankrupt or ceasing operations, termination for cause or termination by the employee other than for good reason, the employment agreements provide for continued salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement. If a change in control occurs during the term of an employee's employment and either party to the agreement terminates the employee's employment as a result thereof, the employee will be entitled to receive salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement.
The employment agreements also provide for a noncompetition period that will continue until the later of one year after the termination of the employee's employment or the date on which the employee is no longer entitled to receive severance payments under the employment agreement. During the noncompetition period, the employees are generally prohibited from engaging in any business that competes with us or our affiliates in areas in which we conduct business as of the date of termination and from soliciting or inducing any of our employees to terminate their employment with us or accept employment with anyone else or interfere in a similar manner with our business.
Crosstex Energy GP, LLC intends to adopt a long-term incentive plan for employees and directors of Crosstex Energy GP, LLC and its affiliates who perform services for us.
The long-term incentive plan consists of two components: restricted units and unit options. The long-term incentive 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 Crosstex Energy GP, LLC's board of directors.
Crosstex Energy GP, LLC's board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Crosstex Energy GP, LLC's board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Restricted Units. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. At the time of this offering, we will not grant any restricted units. In the future, the compensation committee may make additional grants under
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the plan to employees and directors containing such terms as the compensation committee shall determine under the plan. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us, our general partner or Crosstex Energy GP, LLC.
If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by Crosstex Energy GP, LLC in the open market, common units already owned by Crosstex Energy GP, LLC, common units acquired by Crosstex Energy GP, LLC directly from us or any other person or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units.
We intend the issuance of the common units upon vesting of the restricted units under the plan 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 we will receive no remuneration for the units.
Unit Options. The long-term incentive plan currently permits the grant of options covering common units. 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, the unit options will become exercisable upon a change in control of us, our general partner or Crosstex Energy GP, LLC or upon the achievement of specified financial objectives.
At the time of the offering, we expect to grant options to purchase an aggregate of approximately 175,000 common units to employees and directors of Crosstex Energy GP, LLC. The options will have an exercise price equal to the initial public offering price. We expect that Barry E. Davis will receive options to purchase 30,000 common units, James R. Wales and A. Chris Aulds will each receive options to purchase 20,000 common units, Jack M. Lafield and William W. Davis will each receive options to purchase 17,500 common units, and Michael P. Scott will receive options to purchase 12,500 common units.
Upon exercise of a unit option, Crosstex Energy GP, LLC will acquire common units in the open market or directly from us or any other person or use common units already owned by Crosstex Energy GP, LLC, or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Crosstex Energy GP, LLC will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Crosstex Energy GP, LLC also intends to adopt a short-term incentive plan for management and other employees who perform services for us. The short-term incentive plan will be administered by the compensation committee. The proposed short-term incentive plan is designed to enhance our financial performance by rewarding management and employees with cash awards for achieving certain
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performance objectives, including partnership financial targets, individual performance targets or a combination of both. The performance objective for each year will be recommended by the compensation committee of the board of directors. Individual participants and payments each year will be determined by and in the discretion of the compensation committee, and the compensation committee will be able to amend the plan at any time.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows the beneficial ownership of units of Crosstex Energy, L.P. that will be issued upon the completion of this offering and the related transactions held by:
| Name of Beneficial Owner(1) |
Common Units to be Beneficially Owned |
Percentage of Common Units to be Beneficially Owned |
Subordinated Units to be Beneficially Owned |
Percentage of Subordinated Units to be Beneficially Owned |
Percentage of Total Units to be Beneficially Owned |
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|---|---|---|---|---|---|---|---|---|---|---|---|
| Crosstex Energy Holdings Inc. | 333,000 | 14.3 | % | 4,667,000 | 100.0 | % | 71.4 | % | |||
| Barry E. Davis(2)(3) | — | — | — | — | — | ||||||
| James R. Wales(2)(3) | — | — | — | — | — | ||||||
| A. Chris Aulds(2)(3) | — | — | — | — | — | ||||||
| Jack M. Lafield(2)(3) | — | — | — | — | — | ||||||
| William W. Davis(2)(3) | — | — | — | — | — | ||||||
| Michael P. Scott(2)(3) | — | — | — | — | — | ||||||
| C. Roland Haden | — | — | — | — | — | ||||||
| Bryan H. Lawrence(4) | — | — | — | — | — | ||||||
| Sheldon B. Lubar(5) | — | — | — | — | — | ||||||
| Stephen A. Wells | — | — | — | — | — | ||||||
| Robert F. Murchison | — | — | — | — | — | ||||||
| All directors and executive officers as a group (11 persons) | — | — | — | — | — |
The following table shows the beneficial ownership of Crosstex Energy Holdings Inc. upon completion of this offering. Crosstex Energy Holdings Inc. owns Crosstex Energy GP, LLC and,
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together with Crosstex Energy GP, LLC, our general partner and, as reflected above, common units and subordinated units.
| Name of Beneficial Owner(1) |
Percent of Equity |
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|---|---|---|---|
| Yorktown Energy Partners IV, L.P.(2) | 60.1 | % | |
| Yorktown Energy Partners V, L.P.(2) | 15.1 | % | |
| Lubar Nominees(3) | 5.8 | % | |
| Barry E. Davis(4) | 7.8 | % | |
| James R. Wales(4) | 3.5 | % | |
| A. Chris Aulds(4) | 5.2 | % | |
| Jack M. Lafield(4) | * | ||
| William W. Davis(4) | * | ||
| Michael P. Scott(4) | * | ||
| C. Roland Haden | — | ||
| Bryan H. Lawrence(5) | — | ||
| Sheldon B. Lubar(3) | 5.8 | % | |
| Stephen A. Wells | — | ||
| Robert F. Murchison | — | ||
| All directors and executive officers as a group (11 persons)(4) | 23.6 | % | |
| Other(6) | 2.6 | % |
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
After this offering, Crosstex Energy Holdings Inc. will own 333,000 common units and 4,667,000 subordinated units representing an aggregate 70.0% limited partnership interest in us. Our general partner will own a 2% general partner interest in us and the incentive distribution rights. Our general partner's ability, as general partner, to manage and operate Crosstex Energy, L.P. and Crosstex Energy Holdings' ownership of an aggregate 70.0% limited partner interest in us effectively gives our general partner the ability to veto some of our actions and to control our management.
Distributions and Payments to the General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of Crosstex Energy, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's length negotiations.
| The consideration received by our general partner and its affiliates for the transfer of their interests in the subsidiaries which hold our operating assets | • 333,000 common units; | |
| • 4,667,000 subordinated units; | ||
| • the incentive distribution rights; and | ||
| • a 2% general partner interest in Crosstex Energy, L.P. | ||
Operational Stage |
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Distributions of available cash to our general partner and its affiliates |
We will generally make cash distributions of 98% to the unitholders, including affiliates of our general partner, as holders of 333,000 common units and all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level. |
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Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, affiliates of our general partner would receive distributions of approximately $286,000 on the 2% general partner interest and affiliates of our general partner would receive distributions of $10.0 million on their common units and subordinated units. |
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| Payments to our general partner and its affiliates | Our general partner will be entitled to reimbursement for all expenses it incurs on our behalf, including salaries and employee benefit costs for its employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner in connection with operating our business. Our general partner has sole discretion in determining the amount of these expenses. The cost of general and administrative services performed on our behalf will not exceed $6.0 million for the first twelve months following our initial public offering. | |
Withdrawal or removal of our general partner |
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of our General Partner." |
|
Liquidation Stage |
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Liquidation |
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances. |
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Agreements Governing the Transactions
We and other parties have entered into or will enter into the various documents and agreements that will effect transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm's-length negotiations, and they, or any of the transactions that they provide for, may be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with vesting assets into our subsidiaries, will be paid from the proceeds of this offering.
Upon the closing of this offering, we will enter into an agreement with Crosstex Energy Holdings Inc., Crosstex Energy GP, LLC and our general partner which will govern potential competition among us and the other parties to the agreement. Crosstex Energy Holdings Inc. will agree, and will cause its controlled affiliates to agree, for so long as management, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. and its affiliates, or any combination thereof, control our general partner, not to engage in the business of gathering, transmitting, treating, processing, storing and marketing of natural gas and the transportation, fractionation, storing and marketing of NGLs unless it first offers us the opportunity to engage in this activity or acquire this business, and the board of directors of Crosstex Energy GP, LLC, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. In addition, Crosstex
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Energy Holdings Inc. will be able to purchase a business that has a competing natural gas gathering, transmitting, treating, processing and producer services business if the competing business does not represent the majority in value of the business to be acquired and Crosstex Energy Holdings Inc. offers us the opportunity to purchase the competing operations following their acquisition. The noncompetition restrictions in the omnibus agreement will not apply to the assets retained and business conducted by Crosstex Energy Holdings Inc. at the closing of this offering. Except as provided above, Crosstex Energy Holdings Inc. and its controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us. In addition, Yorktown Energy Partners IV, L.P., Yorktown Energy Partners V, L.P. and any affiliated Yorktown funds will not be prohibited from owning or engaging in businesses which compete with us.
Camden Resources, Inc. We treat gas for, and purchase gas from, Camden Resources, Inc. Yorktown Energy Partners IV, L.P. has made equity investments in both Camden and one of the parent entities of the general partner of our general partner. The gas treating and gas purchase agreements we have entered into with Camden are standard industry agreements containing terms substantially similar to those contained in our agreements with other third parties. During the year ended December 31, 2001, our predesessor purchased natural gas from Camden Resources, Inc. in the amount of approximately $17.3 million and received approximately $737,000 in treating fees from Camden Resources, Inc.
Crosstex Pipeline Company. We own general and limited partner interests in Crosstex Pipeline Partners, L.P. that represent a 28% economic interest. We have entered into various transactions with Crosstex Pipeline Partners, and we believe that the terms of these transactions are comparable to those that we could have negotiated with unrelated third parties. The transactions with Crosstex Pipeline Partners include the following:
Vantex Energy Services. During the year ended December 31, 1999 our predecessor sold natural gas to Vantex Energy Services in the amount of $114,000, and purchased natural gas from Vantex Energy Services in the amount of $105,000. Vantex Energy Services was an affiliate of our predecessor by way of equity interests in Vantex Energy Services and our predecessor held by Ray Davis, Kelcy Warren and ETC Investors, Ltd. We do not expect to enter into future transactions with Vantex Energy Services.
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Texas Energy Transfer Company. During the year ended December 31, 1999 and the four months ended April 30, 2000, our predecessor sold natural gas to Texas Energy Transfer Company, an affiliate of our predecessor, in the amounts of $4,278,000 and $234,000, respectively, and purchased natural gas from Texas Energy Transfer Company in the amount of $54,000 and $54,000, respectively. Our predecessor also reimbursed Texas Energy Transfer Company for costs incurred on behalf of our predecessor of $80,000 and $13,000 in the year ended December 31, 1999 and the four months ended April 30, 2000, respectively. Texas Energy Transfer Company was an affiliate of our predecessor by way of equity interests in Texas Energy Transfer Company and our predecessor held by Ray Davis, Kelcy Warren and ETC Investors, Ltd.
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CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Crosstex Energy Holdings Inc.), on the one hand, and Crosstex Energy, L.P. and its limited partners, on the other hand. The directors and officers of our general partner's general partner, Crosstex Energy GP, LLC, have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to Crosstex Energy, L.P. and the unitholders.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our partnership agreement contains provisions that give our general partner significantly greater latitude in resolving conflicts of interests than a director of a corporation would have. In effect, these provisions limit our general partner's fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. Our general partner may, but is not required to, seek the approval of the conflicts committee of the board of directors of the general partner of our general partner of such resolution.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or the unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution will be conclusively deemed fair and reasonable to us if that resolution is:
Unless the resolution is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider:
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
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In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Cash Distribution Policy—Subordination Period."
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, the operating partnership or its operating subsidiaries.
We will reimburse our general partner and its affiliates for expenses.
We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in providing corporate staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by the general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable terms without the limitation on liability.
Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered, provided these services are rendered on terms that are fair and reasonable to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's length negotiations.
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All of these transactions entered into after the sale of the common units offered in this offering are to be on terms that are fair and reasonable to us.
Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
Common units are subject to our general partner's limited call right.
Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."
We may choose not to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who will perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
Our general partner's affiliates may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in the partnership agreement and the omnibus agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.
Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement.
Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by our general partner to limited partners and the partnership. Delaware law has not definitively established the limits on the ability of the partnership agreement to restrict such fiduciary duty.
Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner's general partner have fiduciary duties to manage our general partner in a manner beneficial both to its owners as well as to you. Without these modifications, the general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit the general partner by enabling it to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us as described above. These
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modifications also enable the general partner of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
| State-law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for our partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. | |
Partnership agreement modified standards |
Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner's actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held. |
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Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us under the factors previously set forth. In determining whether a transaction or resolution is "fair and reasonable" our general partner may consider interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held. |
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In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith. |
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Rights and Remedies of Unitholders |
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions could include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. |
In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
We must indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification if our general partner or these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. We also must provide this indemnification for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the Securities and Exchange Commission, such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read "The Partnership Agreement—Indemnification."
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DESCRIPTION OF THE COMMON UNITS
The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Cash Distribution Policy." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."
American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:
There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:
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An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.
A transferee's broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:
Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:
The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent. Please read "The Partnership Agreement—Status as Limited Partner or Assignee."
Until a common unit has been transferred on our books, we and the transfer agent, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
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The following is a summary of the material provisions of our partnership agreement. Our partnership agreement, as well as the partnership agreement of the operating partnership, are included as exhibits to the registration statement of which this prospectus constitutes a part. We will provide prospective investors with a copy of the form of this agreement upon request at no charge. Unless the context otherwise requires, references in this prospectus to the "partnership agreement" constitute references to the partnership agreement of Crosstex Energy, L.P.
We summarize the following provisions of the partnership agreement elsewhere in this prospectus:
We were organized on July 12, 2002 and will have a perpetual existence except as provided below under "—Termination and Dissolution."
Our purpose under the partnership agreement is limited to serving as the limited partner of the operating partnership and engaging in any business activities that may be engaged in by the operating partnership or that are approved by our general partner. The partnership agreement of the operating partnership provides that the operating partnership may, directly or indirectly, engage in:
Although our general partner has the ability to cause us, the operating partnership or its subsidiaries to engage in activities other than gathering, transmission, treating, processing and marketing of natural gas, our general partner has no current plans to do so. Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct our business.
Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, the partnership agreement.
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Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
Our subsidiaries conduct business in four states. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our limited partner interest in the operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held
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personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
The following matters require the unitholder vote specified below. Certain significant decisions require approval by a "unit majority" of the common units. We define "unit majority" as:
| Issuance of additional common units or units of equal rank with the common units during the subordination period | Unit majority, with certain exceptions described under "—Issuance of Additional Securities." | |
Issuance of units senior to the common units during the subordination period |
Unit majority. |
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Issuance of units junior to the common units during the subordination period |
No approval right. |
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Issuance of additional units after the subordination period |
No approval right. |
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Amendment of the partnership agreement |
Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See "—Amendment of the Partnership Agreement." |
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Merger of our partnership or the sale of all or substantially all of our assets |
Unit majority. See "—Merger, Sale or Other Disposition of Assets." |
|
Amendment of the operating partnership agreement and other action taken by us as a limited partner of the operating partnership |
Unit majority if such amendment or other action would adversely affect our limited partners (or any particular class of limited partners) in any material respect. See "—Action Relating to the Operating Partnership." |
|
Dissolution of our partnership |
Unit majority. See "—Termination and Dissolution." |
|
Reconstitution of our partnership upon dissolution |
Unit majority. See "—Termination and Dissolution." |
|
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Withdrawal of the general partner |
The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for the withdrawal of the general partner prior to December 31, 2012 in a manner which would cause a dissolution of our partnership. See "—Withdrawal or Removal of our General Partner." |
|
Removal of the general partner |
Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. See "—Withdrawal or Removal of our General Partner." |
|
Transfer of the general partner interest |
Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all our substantially all of its assets to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2012. See "—Transfer of General Partner Interests." |
|
Transfer of incentive distribution rights |
Except for transfers to an affiliate or another person as part of the general partner's merger or consolidation with or into, or sale of all or substantially all of its assets to or sale of all or substantially all its equity interests to such person, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, voting separately as a class, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2012. See "—Transfer of Incentive Distribution Rights." |
|
Transfer of ownership interests in the general partner |
No approval required at any time. See "—Transfer of Ownership Interests in our General Partner." |
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of the unitholders. During the subordination period, however, except as we discuss in the following paragraph, we may not issue
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equity securities ranking senior to the common units or an aggregate of more than 1,166,500 (1,316,500 if the underwriters exercise their over-allotment option in full) additional common units or units on a parity with the common units, in each case, without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.
During or after the subordination period, we may issue an unlimited number of common units without the approval of unitholders as follows:
It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities interests that, in the sole discretion of our general partner, have special voting rights to which the common units are not entitled.
Upon the issuance of additional partnership securities, other than upon exercise of the underwriters' over-allotment option, our general partner will be required to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
Amendment of the Partnership Agreement
General. Amendments to the partnership agreement may be proposed only by or with the consent of our general partner, which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as we describe below, an amendment must be approved by a unit majority.
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Prohibited Amendments. No amendment may be made that would:
The provision of the partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class.
No Unitholder Approval. Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:
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In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if those amendments, in the discretion of our general partner:
Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under "—No Unitholder Approval" should occur. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners or cause us, the operating partnership or its subsidiaries to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.
Action Relating to the Operating Partnership
Without the approval of holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf, as the limited partner of the operating partnership, to any amendment to the partnership agreement of the operating partnership or taking any action on our behalf permitted to be taken by a limited partner of the operating partnership, in each case that would adversely affect our limited partners (or any particular class of limited partners as compared to other classes of limited partners) in any material respect.
Merger, Sale or Other Disposition of Assets
The partnership agreement generally prohibits our general partner, without the prior approval of the holders of units representing a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our
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behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries as a whole. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.
If conditions specified in the partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity. The unitholders are not entitled to dissenters' rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.
We will continue as a limited partnership until terminated under the partnership agreement. We will dissolve upon:
Upon a dissolution under the last clause, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in the partnership agreement by forming a new limited partnership on terms identical to those in the partnership agreement and having as general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in "Cash Distribution Policy—Distributions of Cash upon Liquidation." The liquidator may defer liquidation of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.
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Withdrawal or Removal of our General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2012 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2012 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interests."
Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. At the closing of this offering, affiliates of the general partner will own 71.4% of the outstanding units.
The partnership agreement also provides that if Crosstex Energy GP, L.P. is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
In the event of removal of the general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive
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distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
Transfer of General Partner Interests
Except for transfer by our general partner of all, but not less than all, of its general partner interest in us and the operating partnership to:
our general partner may not transfer all or any part of its general partner interest in us and the operating partnership to another entity prior to December 31, 2012 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
Transfer of Ownership Interests in our General Partner
At any time, the partners of our general partner may sell or transfer all or part of their partnership interests in the general partner without the approval of the unitholders.
Transfer of Incentive Distribution Rights
Our general partner or its affiliates or a subsequent holder of incentive distribution rights may transfer its incentive distribution rights to an affiliate or to another person as part of its merger or consolidation with or into, or sale of all or substantially all of its assets, or sale of substantially all of its equity interests to, that person without the prior approval of the unitholders; but, in each case, the transferee must agree to be bound by the provisions of the partnership agreement. Prior to December 31, 2012, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units (excluding common units held by the general
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partner or its affiliates). On or after December 31, 2012, the incentive distribution rights will be freely transferable.
Change of Management Provisions
The partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Crosstex Energy GP, L.P. as our general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors.
Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
If at any time our general partner and its affiliates hold more than 80% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:
As a result of our general partner's right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences—Disposition of Common Units."
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted,
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except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as the partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under the partnership agreement will be delivered to the record holder by us or by the transfer agent.
Status as Limited Partner or Assignee
Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.
An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a substitute limited partner at the written direction of the assignee. Please read "—Meetings; Voting." Transferees that do not execute and deliver a transfer application will be treated neither as assignees nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. Please read "Description of the Common Units—Transfer of Common Units."
Non-citizen Assignees; Redemption
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require
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each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.
Under the partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees in its sole discretion, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
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Right to Inspect Our Books and Records
The partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.
Under the partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Crosstex Energy GP, L.P. as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."
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UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus, affiliates of our general partner will hold 333,000 common units and 4,667,000 subordinated units. All of these subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act of 1933, except that any common units owned by an "affiliate" of ours may not be resold publicly other than in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
Sales under Rule 144 are also subject to specific manner of sale provisions, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of our company at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.
Prior to the end of the subordination period, we may not issue equity securities of the partnership ranking prior or senior to the common units or an aggregate of more than 1,166,500 (1,316,500 if the underwriters' over-allotment option is exercised in full) additional common units or an equivalent amount of securities ranking on a parity with the common units, without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, subject to certain exceptions described under "The Partnership Agreement—Issuance of Additional Securities."
The partnership agreement provides that, after the subordination period, we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. The partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."
Under the partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act of 1933 and state laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow the general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.
Crosstex Energy, L.P., Crosstex Energy Holdings Inc., our general partner and the directors and executive officers of the general partner of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.
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This section discusses the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States. It is based upon current provisions of the Internal Revenue Code, existing regulations, proposed regulations to the extent noted, and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Crosstex Energy, L.P. and the operating partnership.
No attempt has been made in the following discussion to comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs), or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P., special counsel to the general partner and to us, and are, to the extent noted herein, based on the accuracy of certain factual matters.
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. An opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not
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taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Baker Botts L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions, that the operating partnership will be disregarded as an entity separate from us for federal income tax purposes so long as the operating partnership does not elect to be treated as a corporation and we will be classified as a partnership so long as:
Qualifying income includes certain income and gains derived from the transportation and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest other than from a financial business, dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that more than 96% of our current income is within one or more categories of income that are qualifying income in the opinion of Baker Botts L.L.P. The portion of our income that is qualifying income can change from time to time.
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Although we expect to conduct our business so as to meet the Qualifying Income Exception, if we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and as if we had then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, treatment of us as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the common units.
The discussion below assumes that we will be treated as a partnership for federal income tax purposes. See the discussion above of the opinion of Baker Botts L.L.P. that we will be treated as a partnership if certain factual matters are, as we expect, favorably resolved.
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Unitholders who have become limited partners of Crosstex Energy, L.P. will be treated as our partners for federal income tax purposes. Also:
will be treated as our partners for federal income tax purposes. Assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, may not be treated as one of our partners for federal income tax purposes. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.
A beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose his status as one of our partners with respect to those common units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of short sales."
No portion of our income, gain, deductions or losses is reportable by a unitholder who is not one of our partners for federal income tax purposes, and any cash distributions received by a unitholder who is not one of our partners for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to the consequences of holding common units for federal income tax purposes.
The following assumes that a unitholder is treated as one of our partners.
Tax Consequences of Unit Ownership
Flow-through of taxable income. Each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions even if no cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution from us. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
Treatment of distributions. Our distributions to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, which are known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."
A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities and result in a corresponding
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deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture and substantially appreciated "inventory items," both as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been distributed his proportionate share of our Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.
Ratio of taxable income to distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through December 31, 2005, will be allocated an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2005, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. In particular, our estimate is based upon our use of a seven year recovery period for our gathering systems and certain other property, which is consistent with a decision of the Court of Appeals for the Tenth Circuit on the issue. The IRS has stated that it will continue to litigate whether the recovery period is seven years or 15 years for taxpayers, such as us, for whom the appeal in any tax controversy would be to another Court of Appeals. The lower courts that have addressed the issue have not been consistent. A district court in Wyoming held that the recovery period for similar property is seven years. The Tax Court and a district court in Michigan have held that the recovery period for similar property is 15 years. If we were required to depreciate our gathering systems over a 15 year recovery period, then we estimate that a purchaser of common units in this offering who owns such common units through December 31, 2005, will be allocated an amount of federal taxable income for such period that will be no more than 30% of the cash distributed with respect to that period, and that after the taxable year ending December 31, 2005, the ratio of allocable taxable income to cash distributions to unitholders will increase. Further, our estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.
Basis of common units. A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions he receives from us, by his share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder generally will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of gain or loss."
Limitations on deductibility of losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for
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which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of our income may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.
A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
Limitations on interest deductions. The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:
The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, a unitholder's share of our portfolio income will be treated as investment income.
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Entity-level collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
Allocation of income, gain, loss and deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner. In order to be able to allocate neither gain nor loss to our unitholders for 2002 (and to provide thereto K-1s which so report), we will allocate our net loss or net income for the portion of 2002 that is after this offering to our general partner. If we have a net loss for such portion of 2002, then we will allocate to our general partner an equal amount of our net income for 2003 or a future period. If we have net income for such portion of 2002, then we will distribute an amount of cash to the general partner that is equal to the net income allocation.
Certain items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our property at the time of this offering. We will use the remedial method with respect to such differences with respect to some, but not all, of our assets, and we may use other methods with respect to some assets. The effect to a unitholder purchasing common units in this offering will, as to those assets in respect of which we use the remedial method, be essentially the same as if the tax basis of such assets was equal to their fair market value at the time of this offering, and the effect of allocations that are made under the traditional method will be essentially the same as if those assets had a tax basis that is less than fair market value. In addition, recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 election" and "—Disposition of Common Units—Allocations between transferors and transferees," the allocations in our partnership agreement will be given effect for federal income tax purposes in determining how our income, gain, loss or deduction will be allocated among the holders of our equity that is outstanding immediately after the offering that is made by this prospectus. Such opinion is, as to certain allocations of items of income, gain, loss and deduction for 2002 to the general partner and away from the unitholders, based upon representations made by an affiliate of the general partner as to expected tax attributes of that affiliate through the end of 2002.
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Treatment of short sales. A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be a partner for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
Baker Botts L.L.P. has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing or loaning their common units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read "—Disposition of Common Units—Recognition of gain or loss."
Alternative minimum tax. Each unitholder will be required to take into account his share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. We do not expect to generate significant tax preference items or adjustments. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in common units on their liability for the alternative minimum tax.
Tax rates. In general, the highest effective United States federal income tax rate for individuals for 2002 is 38.6% and the maximum United States federal income tax rate for net capital gains of an individual for 2002 is 20% if the asset disposed of was held for more than 12 months at the time of disposition.
Section 754 election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets under Section 743(b) of the Internal Revenue Code to reflect his purchase price when he buys common units from a holder thereof. This election does not apply to a person who purchases common units directly from us.
The calculations that are required to determine a Section 743(b) adjustment become more complex after common units in addition to those that are issued in this offering are held by the public. For example, certain regulations require that the portion of the Section 743(b) adjustment that eliminates the effect of any unamortized difference in "book" and tax basis of recovery property to the holder of such a common unit be depreciated over the remaining recovery period of that property, but Treasury Regulation Section 1.167(c)-1(a)(6) may require that any such difference in "book" and tax basis of other property be depreciated over a different period. In addition, the holder of a common unit (other than a common unit that is sold in this offering) may be entitled by reason of a Section 743(b) adjustment to amortization deductions in respect of property to which the traditional method of eliminating differences in "book" and tax basis applies but to which the holder of a common unit that is sold in this offering will not be entitled.
Under our partnership agreement, our general partner is authorized to take a position to preserve our ability to determine the tax attributes of a common unit from its date of purchase and the amount that is paid therefor even if that position is not consistent with the Treasury Regulations.
We intend to depreciate the portion of a Section 743(b) adjustment attributable to any unamortized difference between the "book" and tax basis of an asset in respect of which we use the
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remedial method in a manner that is consistent with the regulations under Section 743 of the Internal Revenue Code as to recovery property in respect of which the remedial allocation method is adopted. Such method is arguably inconsistent with Treasury Regulation Section 1.167(c)-l(a)(6), which is not expected to directly apply to a material portion of our assets. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position which may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. In addition, if common units are held by the public other than those that are sold in this offering and that are entitled to different treatment in respect of property as to which we are using the traditional method of eliminating differences in "book" and tax basis, we may also take a position that results in lower annual deductions to some or all of our unitholders than might otherwise be available. Counsel is unable to opine as to the validity of any position that is described in this paragraph because there is no clear applicable authority.
A Section 754 election is advantageous if the transferee's tax basis in his common units is higher than the common units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his common units is lower than those common units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election.
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. The determinations we make may be successfully challenged by the IRS and the deductions resulting from them may be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than he would have been allocated had the election not been revoked.
Accounting method and taxable year. We will use the year ending December 31 as our taxable year and will adopt the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations between transferors and transferees."
Initial tax basis, depreciation and amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by the general partner and its affiliates. Please read "—Tax Consequences of Unit Ownership—Allocation of income, gain, loss and deduction."
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To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we acquire or construct in the future may be depreciated using accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his units. Please read "—Tax Consequences of Unit Ownership—Allocation of income, gain, loss and deduction" and "—Disposition of Common Units—Recognition of gain or loss."
The costs that we incur in selling our common units ("syndication expenses") must be capitalized and cannot be deducted by us currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which will be amortized by us over a period of 60 months, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
Valuation and tax basis of our properties. The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the fair market values, and determinations of the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the fair market value estimates ourselves. These estimates of value and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates and determinations of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Recognition of gain or loss. Gain or loss will be recognized on a sale of common units equal to the difference between the amount realized and the unitholder's tax basis for the common units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.
Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than his tax basis in that common unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in common units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of common units held more than 12 months will generally be taxed at a maximum rate of 20%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture, other potential recapture items, or other "unrealized receivables" or to "inventory items" we own. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income
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and a capital loss upon a sale of common units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell, but, under the regulations, may designate specific common units sold for purposes of determining the holding period of the common units sold. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of our common units. A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.
The Internal Revenue Code treats a taxpayer as having sold a partnership interest, such as our units, in which gain would be recognized if it were actually sold at its fair market value, if the taxpayer or related persons enters into:
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property.
Allocations between transferors and transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the first business day of the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.
The use of this method may not be permitted under existing Treasury Regulations. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferors and transferees as well as among unitholders whose interests vary during a taxable year to conform to a method permitted under future Treasury Regulations.
A unitholder who owns common units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
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Notification requirements. A purchaser of common units other than an individual who is a citizen of the United States and who purchases through a broker is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may lead to the imposition of substantial penalties.
Constructive termination. We will be considered to have been "terminated" for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A "termination" of us will result in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
Tax-Exempt Organizations and Other Investors
Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies or mutual funds raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.
A regulated investment company, or "mutual fund," is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.
Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest effective tax rate applicable to individuals from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for the taxes withheld. A change in applicable law may require us to change these procedures.
In addition, because a foreign corporation that owns common units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
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Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the common units during the five-year period ending on the date of the disposition and if the common units are regularly traded on an established securities market at the time of the sale or disposition.
Information returns and audit procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which generally will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that any of those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Any challenge by the IRS could negatively affect the value of the common units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement names our general partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
Nominee reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:
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Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.
Registration as a tax shelter. The Internal Revenue Code requires that "tax shelters" be registered with the Secretary of the Treasury. Although we may not be a "tax shelter" for such purposes, we have applied to register as a "tax shelter" with the Secretary of the Treasury in light of the substantial penalties that might be imposed if registration is required and not undertaken.
Issuance of a tax shelter registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.
We will supply our tax shelter registration number to you when one has been assigned to us. A unitholder who sells or otherwise transfers a common unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. A unitholder must disclose our tax shelter registration number on his tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on Form 8271 to be attached to his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.
Accuracy-related penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
More stringent rules apply to "tax shelters," a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders
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might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.
A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.
State, Local, Foreign and Other Tax Consequences
In addition to federal income taxes, you will be subject to other taxes, including state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Texas, Oklahoma, Louisiana, New Mexico and Arkansas. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-level collections." Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.
INVESTMENT IN CROSSTEX ENERGY, L.P. BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
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The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:
Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in the first bullet point above.
Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.
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Subject to the terms and conditions of the underwriting agreement between us and the underwriters, the underwriters have agreed severally to purchase from us the following number of common units at the offering price less the underwriting discount set forth on the cover page of this prospectus.
| Underwriters |
Number of Common Units |
||
|---|---|---|---|
| A.G. Edwards & Sons, Inc. | 666,668 | ||
| Raymond James & Associates, Inc. | 666,666 | ||
| RBC Dain Rauscher Inc. | 666,666 | ||
| Total | 2,000,000 | ||
The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common units if any of the units are purchased. The underwriters are obligated to take and pay for all of the common units offered hereby, other than those covered by the over-allotment option described below, if any are taken.
The underwriters have advised us that they propose to offer the common units to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a concession not in excess of $0.84 per unit. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $0.10 per unit to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters, but any such changes will not affect the net proceeds to be received by us in the offering.
Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase up to 300,000 additional common units at the offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.
To the extent the underwriters exercise such option, the underwriters will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional units as the number set forth next to such underwriter's name in the preceding table bears to the total number of units in the table, and we will be obligated, pursuant to the option, to sell such units to the underwriters.
Crosstex Energy, L.P., Crosstex Energy Holdings Inc., the general partner and the directors and executive officers of the general partner of our general partner have agreed that during the 180 days after the date of this prospectus, they will not, without the prior written consent of A.G. Edwards & Sons, Inc., directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus, (2) to affiliates or (3) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration; provided, however, any recipient of common units will furnish to A.G. Edwards & Sons, Inc. a letter agreeing to be bound by these provisions for the remainder of the 180-day period. A.G. Edwards may, in its sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units prior to the expiration of such 180-day period in whole or in part at anytime without notice. A.G. Edwards has informed us that in the event that consent to a waiver of these restrictions is requested by us or any
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other person, A.G. Edwards, in deciding whether to grant its consent, will consider the unitholder's reasons for requesting the release, the number of units for which the release is being requested, and market conditions at the time of the request for such release. However, A.G. Edwards has informed us that as of the date of this prospectus there are no agreements between A.G. Edwards and any party that would allow such party to transfer any common units, nor does it have any intention of releasing any of the common units subject to the lock-up agreements prior to the expiration of the lock-up period at this time.
Prior to this offering, there has been no public market for the common units. The initial public offering price was determined by negotiation between us and the underwriters. The principal factors considered in determining the public offering price include the following:
The following table summarizes the discounts that Crosstex Energy, L.P. will pay to the underwriters in the offering. These amounts assume both no exercise and full exercise of the underwriters' option to purchase additional common units.
| |
No Exercise |
Full Exercise |
||||
|---|---|---|---|---|---|---|
| Per Unit | $ | 1.40 | $ | 1.40 | ||
| Total | $ | 2,800,000 | $ | 3,220,000 | ||
We expect to incur expenses of approximately $2.5 million in connection with this offering.
We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act.
Until the distribution of the common units is completed, rules of the SEC may limit the ability of the underwriters and certain selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters are permitted to engage in certain transactions that stabilize, maintain or otherwise affect the price of the common units.
In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.
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position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.
Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market.
The underwriters will deliver a prospectus to all purchasers of common units in the short sales. The purchasers of common units in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common units covered by this prospectus.
The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.
At the request of Crosstex Energy, L.P. the underwriters are reserving up to 150,000 common units for sale at the initial public offering price to directors, officers, employees and friends through a directed share program. The number of common units available for sale to the general public in the public offering will be reduced to the extent these persons purchase these reserved units. Any common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus.
Neither Crosstex Energy, L.P. nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither Crosstex Energy, L.P. nor the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.
Because the National Association for Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
No sales to accounts of which the underwriter exercises discretionary authority may be made without the prior written approval of the customer.
A.G. Edwards & Sons, Inc. will earn a fee of $335,000 for financial advisory services rendered to Crosstex Energy Services, L.P. pursuant to an engagement letter dated April 23, 2001. The NASD considers this fee to represent compensation earned in connection with this offering.
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The validity of the common units will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.
The consolidated financial statements of Crosstex Energy Services, Ltd. as of December 31, 2000 and 2001 and for the year ended December 31, 1999 (Predecessor), the four months ended April 30, 2000 (Predecessor), the eight months ended December 31, 2000 and the year ended December 31, 2001, and the balance sheet of Crosstex Energy, L.P. as of August 5, 2002 and the balance sheet of Crosstex Energy G.P., L.P. as of August 5, 2002 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2001 financial statements of Crosstex Energy Services, Ltd. refers to a change in the method of accounting for derivatives.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the Securities and Exchange Commission a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at l-800-SEC-0330.
The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's website.
We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.
Statements included in this prospectus 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 the information set forth in Appendix E, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We and our representatives may from time to time make other oral or written statements which are also forward-looking statements.
These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number or risks and uncertainties. We caution that forward-looking statements are not guarantees and
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that actual results could differ materially from those expressed or implied in the forward-looking statements.
Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Risk Factors," and elsewhere in this prospectus.
You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. Before you invest, you should be aware that the occurrence of any of the events described in "Risk Factors" and elsewhere in this prospectus could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.
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F-1
CROSSTEX ENERGY, L.P.
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Following are our unaudited pro forma financial statements as of September 30, 2002 and for the year ended December 31, 2001 and the nine months ended September 30, 2002. The unaudited pro forma consolidated balance sheet assumes that the offering and the related transactions occurred as of September 30, 2002, and the unaudited pro forma consolidated statements of operations assumes that the offering and related transactions occurred on January 1, 2001. These transaction adjustments are presented in the notes to the unaudited pro forma financial statements. The unaudited pro forma financial statements and accompanying notes should be read together with the financial statements and related notes included elsewhere in the prospectus.
The pro forma financial statements reflect the following transactions:
The pro forma balance sheet and the pro forma statements of operations were derived by adjusting the historical financial statements of Crosstex Energy Services, Ltd. The adjustments are based on currently available information and, therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the offering as contemplated. The pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial statements. The unaudited pro forma financial statements do not purport to present the financial position or results of operations of Crosstex Energy, L.P. had the offering actually been completed as of the dates indicated. Moreover, the statements do not project the financial position or results of operations of Crosstex Energy, L.P. for any future date or period.
F-2
CROSSTEX ENERGY, L.P.
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
September 30, 2002
(in thousands, except unit data)
| |
Crosstex Energy Services |
Capitalization Adjustments |
Offering Adjustments |
Pro Forma |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ASSETS | ||||||||||||||||
| Current assets: | ||||||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ |
40,000 (5,300 (32,200 (2,500 |
(c) )(d) )(e) )(b) |
$ | — | |||||||
| Accounts receivable: | ||||||||||||||||
| Trade | 100,325 | 100,325 | ||||||||||||||
| Imbalances | 145 | 145 | ||||||||||||||
| Related party | 447 | 447 | ||||||||||||||
| Other | 480 | 480 | ||||||||||||||
| Assets from risk management activities | 3,580 | 3,580 | ||||||||||||||
| Prepaid expenses and other | 1,945 | 1,945 | ||||||||||||||
| Total current assets | 106,922 | 0 | 106,922 | |||||||||||||
| Property and equipment: | ||||||||||||||||
| Transmission assets | 35,025 | 35,025 | ||||||||||||||
| Gathering systems | 17,851 | 17,851 | ||||||||||||||
| Gas plants | 37,489 | (1,949 | )(a) | 35,540 | ||||||||||||
| Other property and equipment | 2,562 | 2,562 | ||||||||||||||
| Construction in progress | 10,737 | 10,737 | ||||||||||||||
| 103,664 | (1,949 | ) | — | 101,715 | ||||||||||||
| Accumulated depreciation and amortization | (11,221 | ) | 649 | (a) | (10,572 | ) | ||||||||||
| Total property and equipment, net | 92,443 | (1,300 | ) | — | 91,143 | |||||||||||
| Account receivable from Enron | 2,467 | (2,467 | )(a) | — | ||||||||||||
| Assets from risk management activities | 129 | 129 | ||||||||||||||
| Intangible assets, net | 5,859 | 5,859 | ||||||||||||||
| Goodwill, net | 4,873 | 4,873 | ||||||||||||||
| Investment in limited partnerships | 354 | 354 | ||||||||||||||
| Other assets, net | 1,815 | 1,815 | ||||||||||||||
| Total assets | $ | 214,862 | $ | (3,767 | ) | $ | 0 | $ | 211,095 | |||||||
| LIABILITIES AND PARTNERS' EQUITY | ||||||||||||||||
| Current liabilities: | ||||||||||||||||
| Accounts payable and accrued gas purchases | $ | 107,633 | $ | 107,633 | ||||||||||||
| Accrued imbalances payable | 321 | 321 | ||||||||||||||
| Liability from risk management activities | 4,383 | 4,383 | ||||||||||||||
| Current portion of long-term debt | 50 | 50 | ||||||||||||||
| Other current liabilities | 3,133 | 3,133 | ||||||||||||||
| Distribution payable | — | $ | 2,500 | (a) | $ | (2,500 | )(b) | — | ||||||||
| Total current liabilities | 115,520 | 2,500 | (2,500 | ) | 115,520 | |||||||||||
| Long-term debt | 43,250 | $ | (32,200 | )(e) | 11,050 | |||||||||||
| Liability from risk management activities | 272 | 272 | ||||||||||||||
| Partners' equity: | ||||||||||||||||
| Partners' equity | 56,503 | $ |
(6,267 (50,236 |
)(a) )(b) |
— | |||||||||||
| Common unitholders (2,333,000 units issued and outstanding, pro forma) | 3,253 | (b) | 40,000 (5,300 |
(c) )(d) |
37,953 | |||||||||||
| Subordinated unitholders (4,667,000 units issued and outstanding, pro forma as adjusted) | 45,588 | (b) | 45,588 | |||||||||||||
| Non-managing general partner interest (2% interest with dilutive effect equivalent to 142,857 units issued and outstanding, pro forma as adjusted) | 1,395 | (b) | 1,395 | |||||||||||||
| Other comprehensive income | (683 | ) | (683 | ) | ||||||||||||
| Total partners' equity | 55,820 | (6,267 | ) | 34,700 | 84,253 | |||||||||||
| Total liabilities and partners' equity | $ | 214,862 | $ | (3,767 | ) | $ | 0 | $ | 211,095 | |||||||
See accompanying notes to pro forma financial statements.
F-3
CROSSTEX ENERGY, L.P.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Nine Months Ended September 30, 2002
(in thousands, except per unit data)
| |
Crosstex Energy Services |
Offering Adjustments |
Pro Forma |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues: | ||||||||||||
| Midstream | $ | 311,453 | $ | (174 | )(f) | $ | 311,279 | |||||
| Treating and other | 10,631 | 10,631 | ||||||||||
| Total revenues | 322,084 | (174 | ) | 321,910 | ||||||||
Operating costs and expenses: |
||||||||||||
| Midstream purchased gas | 294,025 | (109 | )(f) | 293,916 | ||||||||
| Treating purchased gas | 3,996 | 3,996 | ||||||||||
| Operating expenses | 7,732 | (89 | )(f) | 7,643 | ||||||||
| General and administrative expenses | 6,247 | (1,747 | )(g) | 4,500 | ||||||||
| Stock based compensation | 33 | 33 | ||||||||||
| Impairments | 3,150 | 3,150 | ||||||||||
| (Profit) loss on energy trading contracts | (2,916 | ) | (2,916 | ) | ||||||||
| Depreciation and amortization | 6,034 | (150 | )(f) | 5,884 | ||||||||
| Total operating costs and expenses | 318,301 | (2,095 | ) | 316,206 | ||||||||
Operating income |
3,783 |
1,921 |
5,704 |
|||||||||
Other income (expense): |
||||||||||||
| Interest expense, net | (2,399 | ) | 1,195 | (h) | (1,204 | ) | ||||||
| Other income | 73 | 73 | ||||||||||
| Total other income (expense) | (2,326 | ) | 1,195 | (1,131 | ) | |||||||
Net income |
$ |
1,457 |
$ |
3,116 |
$ |
4,573 |
||||||
General partner's interest in net income |
$ |
91 |
||||||||||
Limited partners' interest in net income: |
||||||||||||
| Common unit interest | $ | 1,494 | ||||||||||
| Subordinated unit interest | 2,988 | |||||||||||
| Total limited partners' interest in net income | $ | 4,482 | ||||||||||
Net income per limited partner unit—basic and diluted |
$ |
0.64 |
||||||||||
| Weighted average limited partners' units outstanding | 7,000 | (i) | ||||||||||
See accompanying notes to pro forma financial statements.
F-4
CROSSTEX ENERGY, L.P.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Year ended December 31, 2001
(in thousands, except per unit data)
| |
Crosstex Energy Services |
Offering Adjustments |
Pro Forma |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues: | ||||||||||||
| Midstream | $ | 362,673 | $ | (333 | )(f) | $ | 362,340 | |||||
| Treating and other | 24,353 | 24,353 | ||||||||||
| Total revenues | 387,026 | (333 | ) | 386,693 | ||||||||
Operating costs and expenses: |
||||||||||||
| Midstream purchased gas | 344,755 | (262 | )(f) | 344,493 | ||||||||
| Treating purchased gas | 18,078 | 18,078</ | ||||||||||