SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 ___________ FORM 10-K ___________ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 Commission file number: 1-14323 Enterprise Products Partners L.P. (Exact name of registrant as specified in its charter) Delaware 76-0568219 (State or other Jurisdiction of (I.R.S. Employer Identification No.) Incorporation or Organization) 2727 North Loop West, Houston, Texas 77008-1037 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code : (713) 880-6500 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Units New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Aggregate market value of the Common Units held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on March 1, 1999, was approximately $174,138,874. This figure assumes that the directors and executive officers of the General Partner, the Enterprise Products 1998 Unit Option Plan Trust, and the EPOLP 1999 Grantor Trust were affiliates of the Registrant. The registrant had 45,552,915 Common Units outstanding as of March 1, 1999.
ENTERPRISE PRODUCTS PARTNERS L.P. TABLE OF CONTENTS Page No. PART I Items 1 and 2. Business and Properties. 3 Item 3. Legal Proceedings. 25 Item 4. Submission of Matters to a Vote of Security Holders. 25 PART II Item 5. Market for Registrant's Common Equity and Related Unitholder Matters. 26 Item 6. Selected Financial Data. 27 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation. 28 Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 36 Item 8. Financial Statements and Supplementary Data. 36 Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure. 36 PART III Item 10. Directors and Executive Officers of the Registrant. 37 Item 11. Executive Compensation. 39 Item 12. Security Ownership of Certain Beneficial Owners and Management. 40 Item 13. Certain Relationships and Related Transactions. 40 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 43 2
PART I Items 1 and 2. Business and Properties. Enterprise Products Partners L.P. ("Enterprise" or the "Company") is a leading integrated North American provider of processing and transportation services to domestic and foreign producers of natural gas liquids ("NGLs") and other liquid hydrocarbons and domestic and foreign consumers of NGL and liquid hydrocarbon products. The Company manages a fully integrated and diversified portfolio of midstream energy assets and is engaged in NGL processing and transportation through direct and indirect ownership and operation of NGL fractionators. It also manages NGL processing facilities, storage facilities, pipelines, and rail transportation facilities, and methyl tertiary butyl ether ("MTBE") and propylene production and transportation facilities in which it has direct and indirect ownership. The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise Products Company ("EPCO"). The Company completed a public offering of 12,000,000 Common Units, representing a 17.7% interest in the Company on July 27, 1998. The net proceeds of the offering were approximately $243.3 million. EPCO and its affiliates hold 33,552,915 Common Units and 21,409,870 Subordinated Units. The general partner of the Company, Enterprise Products GP, LLC, a majority-owned subsidiary of EPCO, holds a 1.0% general partner interest in the Company and a 1.0101% general partner interest in the Operating Partnership. The principal executive office of the Company is located at 2727 North Loop West, Houston, Texas, 77008-1038, and the telephone number of that office is 713-880-6500. References to, or descriptions of, assets and operations of the Company in this Annual Report include the assets and operations of the Operating Partnership and its subsidiaries as well as the predecessors of the Company. Uncertainty of Forward-Looking Statements and Information. This Annual Report contains various forward-looking statements and information that are based on the belief of the Company and the General Partner, as well as assumptions made by and information currently available to the Company and the General Partner. When used in this document, words such as "anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," and "may," and similar expressions and statements regarding the Company's business strategy and plans and objectives of the Company for future operations, are intended to identify forward-looking statements. Although the Company and the General Partner believe that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected. Among the key risk factors that may have a direct bearing on the Company's results of operations and financial condition are: (a) competitive practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and NGL product prices and production, (c) operational and systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e) the impact of current and future laws and governmental regulations (including environmental regulations) affecting the NGL industry in general, and the Company's operations in particular, (f) loss of a significant customer, and (g) failure to complete one or more new projects on time or within budget. 3
Enterprise Products Operating L.P. owns and operates NGL fractionation, propylene production, isobutane production, storage, pipeline, and import/export assets that were acquired from EPCO. Among these assets are the following joint ventures: . a 33-1/3% economic interest in Belvieu Environmental Fuels ("BEF"), which owns and operates a MTBE production facility. . a 49% economic interest in Mont Belvieu Associates ("MBA"), which owns a 50% interest in a NGL fractionation facility. . a 50% aggregate economic interest in EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK"), which own a refrigerated NGL marine terminal loading facility. . a 27.5% economic interest in Baton Rouge Fractionators LLC ("BRF"), which owns a NGL fractionation facility that is under construction. . a 33-1/3% economic interest in Wilprise Pipeline Company, LLC ("Wilprise"), which owns a NGL pipeline system that is under construction. . a 16-2/3% economic interest in Tri-States NGL Pipeline, LLC ("Tri- States"), which owns a NGL pipeline system that is under construction. 4
The following chart shows the organizational structure and ownership of entities: [CHART APPEARS HERE] Sorrento Pipeline Company, LLC, Cajun Pipeline Company, LLC and Chunchula Pipeline Company, LLC own NGL pipelines located in the southeastern United States. Propylene Pipeline Partnership, L.P. owns interests in propylene pipelines located in Texas and Louisiana. HSC Pipeline Partnership, L.P. owns NGL pipeline assets in Mont Belvieu, Texas and the Houston ship channel area. Enterprise Products Texas Operating L.P. owns a 49% interest in MBA which owns a 50% interest in a NGL fractionation facility. Business Strategy The Company's business strategy is to grow its core assets and maximize the returns to Unitholders. The Company intends to pursue this strategy principally by: Capitalizing on Expected Increases in NGL Production. The Company believes production of both oil and natural gas in the Gulf of Mexico will continue to increase over the next several years. The Company intends to capitalize on its existing infrastructure, market position, 5
strategic relationships and financial flexibility to expand its operations to meet the anticipated increased demand for NGL processing services. Of particular significance will be production associated with the development of natural gas fields in Mobile Bay and the Gulf of Mexico offshore Louisiana, which are expected to produce natural gas with significantly higher NGL content than typical domestic production. The Company believes the Gulf Coast is the only major marketplace that has sufficient storage facilities, pipeline distribution systems and petrochemical and refining demand to absorb this new NGL production. Expanding through Construction of Identified New Facilities. The Company is participating in a joint venture to own a new 60,000 barrel per day NGL fractionation facility (expandable to 100,000 barrels per day) near Baton Rouge, Louisiana that is currently under construction. The Company will operate the fractionator and will process NGLs from the Mobile Bay/Pascagoula and south Louisiana areas. In association with this project, the Company is participating in the Wilprise NGL pipeline system, and in January 1999, the Company completed the transaction to form the Tri-States Pipeline joint venture. These pipeline systems will transport NGLs from Mobile Bay and south Louisiana to near Baton Rouge. The Company is participating in a joint venture to own a NGL product chiller that is under construction and will be operated by the Company at its NGL import/export facility (the "NGL Product Chiller") on the Houston ship channel. This facility will improve the Company's ability to load refrigerated butane and propane onto tankers for export. The Company's participation in these new projects is described in the following table: <TABLE> <CAPTION> Estimated Cost to the Company's Planned Company Ownership Project Status Start-Up Date (in millions) Percentage ------- ------ ------------- ------------- ---------- <S> <C> <C> <C> <C> Tri-States Pipeline Under construction 2nd QTR 1999 $14.5 16-2/3% Wilprise Pipeline Under construction 2nd QTR 1999 7.7 33-1/3% Baton Rouge Fractionator Under construction 2nd QTR 1999 24.6 27.5% NGL Product Chiller Under construction 4th QTR 1999 11.0 50.0% ----- $57.8 ===== </TABLE> Investing with Strategic Partners. The Company will continue to pursue joint investments with oil and natural gas producers that can commit feedstock volumes to new facilities or with petrochemical companies that agree to purchase a significant portion of the production from new facilities. For example, the Company will be partners with Amoco, Exxon and Williams in the Baton Rouge fractionation facility; with Amoco, Duke Energy, Koch, Tejas (a Shell subsidiary) and Williams in the Tri-States pipeline; and with Amoco and Williams in the Wilprise pipeline. The Company believes commitments from producers to bring NGL volumes to new fractionation facilities and pipelines are central to establishing the viability of new investments in the NGL processing and transportation industry. Expanding Through Acquisitions. The Company intends to analyze potential acquisitions, joint ventures or similar transactions with businesses that operate in complementary markets and geographic regions. In recent years, major oil and natural gas companies have sold non-strategic assets including assets in the mid-stream natural gas industry. The Company believes this trend will continue and further expects independent oil and natural gas companies to consider similar options. Managing Commodity Price Exposure. A substantial portion of the Company's operations are conducted pursuant to tolling contracts or involve NGL transportation where the Company does not take title to its customer's products, but rather processes or transports a raw feedstock or product for a fee. When the Company does take title to the products it processes, it generally attempts to match the timing and price of its feedstock purchases with those of the sales of end products so as to reduce exposure to fluctuations in commodity prices. The Company generally does not use derivatives to manage its commodity risk. 6
General The Company is a leading integrated provider of processing and transportation services to producers of NGLs and consumers of NGL products. The Company (i) fractionates for a processing fee mixed NGLs produced as by-products of oil and natural gas production into their component products: ethane, propane, isobutane, normal butane and natural gasoline; (ii) converts normal butane to isobutane through the process of isomerization; (iii) produces MTBE from isobutane and methanol; and (iv) transports NGL products to end users by pipeline and railcar. The Company also separates high purity propylene from refinery-sourced propane/propylene mix and transports high purity propylene to plastics manufacturers by pipeline. Products processed by the Company generally are used as feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and commercial heating. The Company's processing operations are concentrated in Mont Belvieu, Texas, which is the hub of the domestic NGL industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United States. The facilities operated by the Company at Mont Belvieu include: (i) one of the largest NGL fractionation facilities in the United States with an average production capacity of 210,000 barrels per day; (ii) the largest butane isomerization complex in the United States with an average isobutane production capacity of 116,000 barrels per day; (iii) one of the largest MTBE production facilities in the United States with an average production capacity of 14,800 barrels per day; and (iv) two propylene fractionation units with an average combined production capacity of 30,000 barrels per day. The Company owns all of the assets at its Mont Belvieu facility except for the NGL fractionation facility, in which it owns an effective 37.0% economic interest; one of the propylene fractionation units, in which it owns a 54.6% interest and controls the remaining interest through a long-term lease; the MTBE production facility, in which it owns a 33-1/3% interest; and one of its three isomerization units and one deisobutanizer which are held under long-term leases with purchase options. The Company also owns and operates approximately 35 million barrels of storage capacity at Mont Belvieu and elsewhere that are an integral part of its processing operations, a network of approximately 500 miles of pipelines along the Gulf Coast and a NGL fractionation facility in Petal, Mississippi with an average production capacity of 7,000 barrels per day. The Company also leases and operates one of only two commercial NGL import/export terminals on the Gulf Coast. The Company's operating margins are derived from services provided to tolling customers and from merchant activities. In its toll processing operations, the Company does not take title to the product and is simply paid a fee based on volumes processed. The Company's profitability from toll processing operations depends primarily on the volumes of NGLs and refinery-sourced propane/propylene mix processed and transported and the level of associated fees charged to its customers. The profitability of the Company's toll processing operations is largely unaffected by short-term fluctuations in the prices for oil, natural gas or NGLs. In its merchant activities, the Company takes title to feedstock products and sells processed end products. The Company's profitability from merchant activities is dependent on the prices of its feedstocks and end products, which typically vary on a seasonal basis. In its merchant activities, the Company generally seeks to reduce commodity price exposure by matching the timing and price of its feedstock purchases with sales of end products. The Company has expanded rapidly since its inception in 1968, primarily through internal growth and the formation of joint ventures. This growth reflects the increased demand for NGL processing due to increased domestic natural gas production and crude oil refining and increased demand for processed NGLs in the petrochemical industry. Over the last few years the Company has increased its NGL fractionation capacity by approximately 35%, built a third isomerization unit that increased its isobutane production capacity by approximately 60%, increased deisobutanizer capacity by approximately 54%, constructed a second propylene fractionation unit which approximately doubled production capacity and made its investment in the MTBE facility at Mont Belvieu. The Company believes the demand for its services will continue to increase, principally as a result of expected increases in natural gas production, particularly in the Gulf of Mexico, and 7
generally increasing domestic and worldwide petrochemical production. Accordingly, the Company has initiated several new projects which are currently in construction. The Company has only one reportable segment: NGL Operations. This segment is reported on under five distinct business units: NGL Fractionation, Isomerization, MTBE Production, Propylene Fractionation, and Other Businesses. For a discussion of the financial results of these business units over the last three fiscal years, see "Management's Discussion and Analysis of Financial Condition and Results of Operation." For total consolidated revenues over the last three fiscal years, see the section labeled "Selected Financial Data." NGL Fractionation General The three principal sources of NGLs fractionated in the United States are (i) domestic gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. When produced at the wellhead, natural gas consists of a mixture of hydrocarbons that must be processed to remove NGLs and other impurities. Gas processing plants are located near the production area and separate pipeline quality natural gas (principally methane) from NGLs and other materials. After being extracted in the field, mixed NGLs, sometimes referred to as "y-grade" or "raw make," are typically transported to a centralized facility for fractionation. Crude oil and condensate production also contain varying amounts of NGLs, which are removed during the refining process and are either fractionated by refiners or delivered to NGL fractionation facilities. Domestic NGL production has increased in recent years, and the Company believes, based on published industry data and its knowledge of the industry, that this supply growth will continue over the next several years. The mixed NGLs delivered from gas plants to centralized fractionation facilities like those operated by the Company at Mont Belvieu are typically transported by NGL pipelines. The following table lists the primary NGL pipelines which connect to the Company's NGL fractionation facilities and the other sources of mixed NGL supply: <TABLE> <CAPTION> Source Parties Served Area of Origination ------ -------------- ------------------- <S> <C> <C> <C> Black Lake Pipeline Enterprise/Dynegy North Louisiana Central Louisiana East Texas Chaparral Pipeline Common Carrier West Texas North Texas Dean Pipeline Enterprise* South Texas Enterprise Import/Export Facility Enterprise* Foreign imports Enterprise Rail/Truck Terminal Common Carrier United States Houston Ship Channel Pipeline Enterprise* Foreign Imports Local Refineries Panola Pipeline Enterprise* East Texas Seminole Pipeline Common Carrier Rocky Mountains Mid-Continent West Texas West Texas LPG Pipeline Common Carrier West Texas North Texas East Texas --------------------------- * NGLs from these sources are delivered exclusively to the Company's Mont Belvieu NGL fractionation facilities. </TABLE> 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 heating, engine and industrial fuel. Isobutane is 8
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 in refinery alkylation to enhance the octane content of motor gasoline and in the production of MTBE, an oxygenation additive in cleaner burning motor gasoline. 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. The Company's NGL Fractionation Facilities At Mont Belvieu, the Company operates one of the largest NGL fractionation facilities in the United States with an average production capacity of 210,000 barrels per day. Mont Belvieu is approximately 25 miles east of Houston and is the hub of the domestic NGL industry because of its proximity to the petrochemical and refinery markets of the Gulf Coast and its location on a large naturally-occurring salt dome that provides for the underground storage of significant quantities of NGLs. Excluding NGLs fractionated in facilities which are captive to certain refineries (non-commercial fractionation), approximately one-half of all NGLs fractionated in the United States are fractionated at Mont Belvieu, and the Company's fractionation facilities currently account for approximately 33% of total NGL fractionation capacity at Mont Belvieu. The Company's Mont Belvieu NGL fractionation facilities include two fractionation trains. Each train consists of a series of towers and is named after the point of origin of the NGL pipelines from which the facilities were originally fed. The West Texas Fractionator was constructed in 1980 with an average production capacity of 35,000 barrels per day and was expanded to 70,000 barrels per day capacity in 1988 and 115,000 barrels per day capacity in 1996. The Seminole Fractionator was constructed in 1982 with an average production capacity of 60,000 barrels per day and was expanded to 95,000 barrels per day capacity in 1985. The individual towers within the fractionation trains are de- ethanizers, depropanizers, debutanizers and deisobutanizers ("DIBs"). The two fractionation trains currently include three de-ethanizers, three depropanizers, three debutanizers and one DIB. The Company owns an effective 37.0% economic interest in the NGL fractionation facilities at its Mont Belvieu complex. The remaining interests are owned by Kinder Morgan (25.0%), Burlington Resources (12.5%), Texaco (12.5%), Union Pacific Resources (12.5%) and EPCO (0.5%). The Company operates the facilities pursuant to an operating agreement that extends for their useful operating life. The Company also owns and operates a NGL fractionation facility at Petal, Mississippi. The Petal facility has two depropanizers and two DIBs with an average production capacity of approximately 7,000 barrels per day. The Petal facility is connected to the Company's Chunchula pipeline system and serves NGL producers in Mississippi, Alabama and Florida. The Company is participating in a joint venture with Amoco, Exxon and Williams to own a 60,000 barrel per day NGL fractionation facility near Baton Rouge, Louisiana. Construction of the facility is underway, with start-up scheduled during the second quarter of 1999. The Company will operate the facility and holds a 27.5% ownership interest at December 31, 1998. It is expected that Amoco, Exxon, and Williams will provide an adequate supply of NGLs produced in Alabama, Mississippi and southern Louisiana including offshore areas to ensure the plant will operate at full capacity. The Company's NGL Fractionation Customers and Contracts The Company primarily processes NGLs for a toll processing fee. Fractionation contracts typically include a base processing fee per gallon subject to adjustment for changes in natural gas, electricity and labor costs, which are the principal variable costs in NGL fractionation. NGL producers generally retain title to, and the pricing risks associated with, the NGL products. 9
The Company has long-term fractionation agreements with Burlington Resources, Texaco and Union Pacific Resources, each of which is a significant producer of NGLs and a co-owner of the Mont Belvieu NGL fractionation facility. Burlington Resources and Texaco have agreed to deliver either a minimum of 39,000 barrels per day of mixed NGLs or all of their mixed NGLs brought within 50 miles of Mont Belvieu. Union Pacific Resources has agreed to deliver 26,000 barrels per day of mixed NGLs as well as additional barrels that exceed its commitments to other facilities. The Company generally enters into contracts that cover most of the remaining capacity at the facilities for one to three- year terms with customers such as Lyondell, Aquila Energy, Enron, Exxon, Williams and Marathon/Ashland. The Company also purchases a small quantity of mixed NGLs from oil and natural gas producers who prefer to sell at the gas processing plant or the fractionation facility. The Company resells the separated components of these NGLs in the spot market or uses them as feedstock for its other operations. The following table demonstrates the volumes of NGLs at the Mont Belvieu facility accounted for by the joint owners in 1998: Principal 1998 NGL Fractionation Customers Average Total Percent of Daily 1998 Total 1998 Customer Name Volumes Volumes Volumes --------------------------------- ------- ------- ------- (thousands (millions of of barrels) barrels) Joint Owners Burlington Resources 45.4 16.6 24% Union Pacific Resources 60.4 22.0 32% Texaco 37.1 13.6 19% Enterprise 5.6 2.0 3% --------------------------- Joint Owners Total 148.5 54.2 78% All Others (12 Processing Customers) 42.7 15.6 22% --------------------------- Total Processing 191.2 69.8 100% =========================== In each of the last five years, the Mont Belvieu fractionation facilities have operated at more than 90% capacity. The following table shows the volumes of mixed NGLs fractionated and the utilization at these facilities over this period: Mont Belvieu NGL Fractionation Volumes and Utilization <TABLE> <CAPTION> 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Average daily production volume (thousands of barrels) 158 158 166 189 191 Average capacity utilization (a) 95% 95% 97% 92% 92% Tolling volume as a percentage of total volume 94% 86% 90% 96% 96% </TABLE> ------------------- (a) The Company completed an expansion of the facilities in November 1996, which increased capacity from 165,000 barrels per day to 210,000 barrels per day. This increased production capacity was not fully utilized until mid-1997. Capacity utilization is based on days the facilities are in operation and may vary from the stated capacity of the facilities. Isomerization General Isomerization is the process of converting normal butane into mixed butane, which is subsequently fractionated into isobutane and normal butane. The demand for commercial isomerization services depends on requirements for isobutane in excess of naturally occurring isobutane that is produced from fractionation and refinery operations. The profitability of isomerization operations is largely dependent upon the differential in the prices of normal butane and isobutane. The spread between the prevailing prices of normal butane and isobutane must be sufficient to support the conversion of normal butane into isobutane by the isomerization process. 10
It is generally uneconomical to convert normal butane into isobutane when the price spread is too narrow. To satisfy its customers' requirements at these times, the Company has either purchased isobutane in the market or separated isobutane from mixed butane held in inventory. Isobutane is principally supplied by NGL fractionation and commercial isomerization units, such as those operated by the Company. The principal sources of demand for isobutane are refineries for alkylation, petrochemical companies for the production of propylene oxide and MTBE producers. The Company's Isomerization Facilities The Company's Mont Belvieu facility includes three butane isomerization units and eight DIBs which comprise the largest butane isomerization complex in the United States. The Company's facilities have an average combined production capacity of 116,000 barrels of isobutane per day and account for more than 70% of the commercial isobutane production capacity in the United States. The Company built its first two isomerization units ("Isom I and II") in 1981, each with a capacity of 13,500 barrels per day. In 1991 and 1992, the capacity of each of these units was increased to 36,000 barrels per day. The third isomerization unit ("Isom III") was completed in 1992 with a capacity of 44,000 barrels per day. The Company has the operating flexibility to switch the process streams from its isomerization units among different DIB units in order to maximize overall plant efficiency. The Company is also able to process fluoridic, lower cost butanes from oil refineries, which it would otherwise be unable to process, by first passing those butanes through an associated defluorinator. The Company's Isomerization Customers and Contracts The Company uses its isomerization facilities to convert normal butane to isobutane for its tolling customers and to meet isobutane sales contracts. The Company's most significant processing customers typically operate under long- term contracts. Lyondell accounted for approximately 38.9% of the Company's isomerization volumes in 1998. The Company's current contract with Lyondell has a ten-year term which expires in December 2009. Lyondell supplies the normal butane feedstock and pays the Company a processing fee based on the gallons of isobutane produced. Lyondell uses the isobutane processed by the Company to produce propylene oxide and MTBE. The Company also has significant isomerization processing contracts with Huntsman, Sun and Mitchell pursuant to which the customers supply the Company with normal butane feedstock and pay the Company a processing fee based on the gallons of isobutane produced. Sun and Mitchell use the isobutane processed for them by the Company to meet their feedstock obligations as partners in the BEF MTBE production facility. The Company can also meet its own obligation to provide isobutane feedstock to the BEF MTBE facility with production from its isomerization unit. 11
As the following table indicates, processing contracts, together with volumes processed by the Company to meet its obligations to BEF, accounted for almost 90% of utilization in 1998: Principal 1998 Isomerization Processing Customers Average Total Percent of Daily 1998 Total 1998 Customer Name Volumes Volumes Volumes ------------- ------- ------- ------- (thousands (millions of of barrels) barrels) BEF Enterprise 4.9 1.8 7.4% Mitchell 5.0 1.8 7.5% Sun 5.0 1.8 7.5% ----------------------------------- BEF Subtotal 14.9 5.4 22.4% Lyondell 25.9 9.5 38.9% Huntsman 16.5 6.0 24.8% ----------------------------------- Total 57.3 20.9 86.1% =================================== In addition to its processing contracts, the Company has also entered into contracts to sell isobutane to Global Octanes, Texas Petrochemicals, Equistar, Citgo, Crown Central and Texaco. The Company has long-standing business relationships with Global Octanes and Texas Petrochemicals. Both of these contracts were renegotiated in 1998 and provide for the delivery of isobutane on the Company's pipeline for a fee. The term of the Global contract extends to April 2002, and the Texas Petrochemicals contract extends to August 2003. Prices under these contracts generally are based on the spot market price for isobutane at Mont Belvieu. The Company can meet its sales obligations either by (i) purchasing normal butane in the spot market and isomerizing it, (ii) purchasing mixed butane on the spot market, including imports, and processing it through a DIB or (iii) purchasing isobutane in the spot market. When the price differential between normal butane and isobutane is not substantial enough to justify isomerization, the Company purchases isobutane and delivers it to its sales customers who pay market-based prices. Accordingly, the percentage of isomerization volumes represented by processing customers increases when the spread between normal butane and isobutane prices is narrow. The following table describes the volumes of isobutane produced and the utilization at the Company's Mont Belvieu facility during the past five years: Isomerization Volumes and Utilization <TABLE> <CAPTION> 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Average daily toll processing volume (a) 45 57 59 62 57 Average daily production volume (a) 66 67 71 67 67 Tolling volume as a percentage of total production 68% 86% 84% 92% 86% Average capacity utilization 57% 58% 61% 57% 57% Average daily merchant volume (a)(b) 42 44 52 53 41 </TABLE> ---------------------------- (a) Thousands of barrels per day (b) Average daily merchant volume includes merchant processing volume and sales of isobutane purchased in the spot market Mixed Butane Fractionation The Company also uses its DIB units to fractionate mixed butane produced from the Company's NGL fractionation and isomerization facilities and from imports and other outside sources into isobutane and normal butane. The operating flexibility provided by its multiple DIBs enables the Company to take advantage of fluctuations in demand and prices for the different types of butane. The Company also has DIB capacity available for toll processing of mixed butane streams for third parties. 12
Imports are the Company's most significant outside source of mixed butane. The Company leases and operates a NGL import/export facility on the Houston ship channel, one of only two commercial facilities on the Gulf Coast capable of receiving and unloading world-scale NGL tankers. This facility, which is connected to the Mont Belvieu facility via a pipeline which is part of the Company's Houston ship channel system, enables the Company to import large quantities of mixed butane for processing in its DIBs. During 1998, imports, primarily from Algeria, Mexico and Venezuela, accounted for 92% of the Company's supply of mixed butane from outside sources. The Company believes, because of new projects in Africa and South America and the lack of storage capacity in the Middle East, NGL import volumes will remain consistent over the near term. MTBE Production General MTBE is produced by reacting methanol with isobutylene, which is derived from isobutane. MTBE was originally used as an octane enhancer in motor gasoline, partly in response to the lead phase-down program begun in the mid- 1970s. Following implementation of the Clean Air Act Amendments of 1990, MTBE became a widely-used oxygenate to enhance the clean burning properties of motor gasoline. Although oxygen requirements can be obtained by using various oxygenates such as ethanol, ethyl tertiary butyl ether (ETBE) and tertiary amyl methyl ether (TAME), MTBE has gained the broadest acceptance due to its ready availability and history of acceptance by refiners. Additionally, motor gasoline containing MTBE can be transported through pipelines, which is a significant competitive advantage over alcohol blends. Substantially all of the MTBE produced in the United States is used in the production of oxygenated motor gasoline that is required to be used in carbon monoxide and ozone non-attainment areas pursuant to the Clean Air Act Amendments of 1990 and the California oxygenated motor gasoline program. Demand for MTBE is primarily affected by the demand for motor gasoline in these areas. Motor gasoline usage in turn is affected by many factors, including the price of motor gasoline (which is dependent upon crude oil prices) and general economic conditions. Historically, the spot price for MTBE has been at a modest premium to gasoline blend values. Future MTBE demand is highly dependent on environmental regulation, federal legislation and the actions of individual states. The Company's MTBE Production Facilities The Company owns a 33-1/3% interest in BEF, the joint venture that owns the MTBE production facility located within the Company's Mont Belvieu complex. Both Sun and Mitchell own 33-1/3% interests in BEF. The BEF facility was completed in 1994 and has an average MTBE production capacity of 14,800 barrels per day. The Company operates the facility under a long-term contract. The Company's MTBE Customers and Contracts Each of the owners of BEF is responsible for supplying one-third of the facility's isobutane feedstock through June 2004. Sun and Mitchell have each contracted to supply their respective portions of the feedstock from the Company's isomerization facilities. The methanol feedstock is purchased from third parties under long-term contracts and transported to Mont Belvieu by a dedicated pipeline which is part of the Company's Houston ship channel system. Sun has entered into a contract with BEF under which Sun is required to take all of BEF's production of MTBE through May 2005. Under the terms of its agreement with BEF, through May 2000, Sun is required to pay the higher of a floor price (approximately $0.78 per gallon at December 31, 1998) or a market-based price for the first 193,450,000 gallons per contract year of production (equivalent to approximately 12,600 barrels per day) from the BEF facility, subject to quarterly adjustments on certain excess volumes. Sun is required to pay a market-based price for volumes produced in 13
excess of 193,450,000 gallons per contract year. Since the contract year begins on June 1, if the facility produces at full capacity during the year, it reaches 193,450,000 gallons of production near the end of March, and sales thereafter through the end of May are at market-based prices. Generally, the price charged by BEF to Sun for MTBE has been above the spot market price for MTBE. The average Gulf Coast MTBE spot price was $.46 per gallon for December 1998 and $.64 per gallon for all of 1998. Beginning in June 2000, pricing on all volumes will convert to market-based rates. The following table shows the production volumes and utilization at BEF's MTBE facility over the past five years: <TABLE> <CAPTION> MTBE Volumes and Utilization 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Average daily production volume (thousands of barrels) 7.8 9.6 13.2 14.4 14.0 Average capacity utilization 70% 65% 89% 97% 95% </TABLE> Propylene Fractionation General Polymer grade, or high purity, propylene is one of three grades of propylene sold in the United States and is used in the petrochemical industry for the production of plastics. High purity propylene is typically over 99.5% pure propylene and is derived by purifying either of the lower grade propylene feedstocks, refinery grade or chemical grade. Chemical grade propylene is 92-93% pure propylene and is produced as a by-product of olefin (ethylene) plants. The supply of chemical grade propylene is insufficient to meet the demand for high purity propylene; therefore, remaining demand is satisfied by the purification of refinery grade propylene. Refinery grade propylene, or propane/propylene mix, is 50-70% pure propylene, with the primary impurity being propane. Propane/propylene mix is produced in crude oil refinery fluid catalytic cracking plants and is fractionated to separate propane and other impurities from the high purity propylene. The fractionation process occurs either at the crude oil refinery or at a commercial propylene fractionation facility like those operated by the Company. Since 1995, domestic high purity propylene production has remained fairly constant, aggregating approximately 112,000 barrels per day in 1998. Polypropylene production accounts for approximately one-half of the demand for high purity propylene. Polypropylene has a variety of end uses, including fiber for carpets and upholstery, packaging film and molded plastic parts for appliance, automotive, houseware and medical products. Another use for propylene is to produce alkylate for blending into gasoline. The Company's Propylene Facilities In 1979, the Company, together with Montell (a Shell subsidiary), constructed its first propylene fractionation unit. The unit, which is also called a "splitter," had an initial average production capacity of 5,500 barrels per day. The facility has been expanded over the years to a current average propylene production capacity of 16,500 barrels per day. The Company owns a 54.6% interest in the splitter, and Montell owns the remaining 45.4% interest. The Company leases Montell's interest. In response to strong demand, the Company constructed a second propylene fractionation unit in March 1997. The new unit has an average production capacity of 13,500 barrels per day. The Company is the sole owner of the second splitter; however, Mobil has an option to purchase a 25.0% interest in the splitter for approximately $13.75 million for a one-year period ending September 30, 1999. Together, the splitters have an average production capacity of 30,000 barrels per day of high purity propylene. 14
The Company is able to unload barges carrying propane/propylene mix through its import/export facility on the Houston ship channel. The Company is also able to receive supplies of propane/propylene mix from its truck and rail loading facility and from refineries and other propane/propylene mix producers through its pipeline located along the Houston ship channel. The Company's Propylene Customers and Contracts The Company produces high purity propylene both as a toll processor and for sale pursuant to long-term agreements with market-based pricing and on the spot market. The Company's most significant toll processing contracts are with Equistar and Huntsman. Pursuant to those contracts, the Company is guaranteed certain minimum volumes and paid a processing fee based on the pounds of high purity propylene processed. The Company also has a toll processing contract with Montell. The Company has several long-term high purity propylene sales agreements, the most significant of which is with Montell. Pursuant to the Montell agreement, the Company agrees to sell Montell 700 million pounds, equal to approximately 11,000 barrels per day, of high purity propylene each year at market-based prices. The Company has supplied Montell with propylene since the first splitter facility was constructed in 1979. The contract is currently scheduled to expire on December 31, 2004. Montell has the option to renew the contract for another 12 years. To meet its sales obligations, the Company has entered into several long-term agreements to purchase propane/propylene mix. The Company's most significant feedstock contracts are with Mobil and Shell. Principal 1998 Propylene Fractionation Customers Average Total Percent of Daily 1998 Total 1998 Customer Name Volumes Volumes Volumes --------------------- ------- ------- ------- (thousands (millions of of barrels) barrels) Processing Customers: Montell 1.1 0.4 4.3% Equistar 6.2 2.3 24.4% Huntsman 3.7 1.4 14.9% Chevron 1.1 0.4 4.3% --------------------------------- Total Processing 12.1 4.5 47.9% Sales Customers: Montell 10.9 4.0 42.5% Huntsman 1.2 0.4 4.3% Other 1.4 0.5 5.3% --------------------------------- Total Sales 13.5 4.9 52.1% --------------------------------- Total 25.6 9.4 100.0% ================================= The following table shows the volumes of propylene produced and utilization at the Company's facilities over the past five years: <TABLE> <CAPTION> Propylene Fractionation Volumes and Utilization 1994 1995 1996 1997 1998 <S> <C> <C> <C> <C> <C> Average daily production volume (thousands of barrels) 14 16 16 26 26 Average capacity utilization (a) 84% 100% 100% 93% 85% Tolling volumes as a percentage of total volume 35% 35% 33% 47% 47% </TABLE> ---------------------------- (a) The Company began operating its second splitter in March 1997 resulting in an increase in capacity to 30,000 barrels per day. During the last six months in 1997, average daily production volume was 29,000 barrels per day. 15
Other Businesses Storage NGLs, NGL products, propane/propylene mix and other light hydrocarbons must be pressurized or refrigerated for storage or transportation in a liquid state. Above-ground storage of these materials in refrigerated or pressurized containers is uneconomical in the quantities required for efficient processing and industrial consumption. For this reason, such materials are typically stored in underground caverns, or wells, within salt domes or salt beds. These salt formations provide a medium which is impervious to the stored products and can contain large quantities of hydrocarbons in a safer manner and at a significantly lower per-unit cost than any above-ground alternative. Brine is used to displace the stored products and to maintain pressure in the well as product volumes fluctuate. The Company owns nine storage wells at Mont Belvieu with an aggregate capacity of approximately 20 million barrels. The Company also owns NGL storage caverns in Breaux Bridge, Louisiana and Petal, Mississippi with additional capacity of 15 million barrels. Several of the wells at Mont Belvieu are used to store mixed NGLs and propane/propylene mix that have been delivered for processing. Such storage allows the Company to mix various batches of feedstock and maintain a sufficient supply and stable composition of feedstock to the processing facilities. The Company stores certain fractionated products for its customers when they are unable to take immediate delivery. These products include propane, isobutane, normal butane, mixed butane and high purity propylene. The Company's storage and product handling facilities and pipeline systems also enable it to unload feedstocks and load processed products on marine tankers at maximum rates. Some of the Company's processing contracts allow for a short period of free storage (typically 30 days or less) and impose fees based on volumes stored for longer periods. Pipelines The Company owns and operates a network of approximately 500 miles of NGL, NGL product and propylene pipelines in the Gulf Coast area. The following table identifies the Company's primary pipeline assets as of December 31, 1998: <TABLE> <CAPTION> Company Ownership Pipeline System Location Miles Function Percentage --------------- -------- ----- -------- ---------- <S> <C> <C> <C> <C> Houston Ship Channel Mont Belvieu to 175 Delivers NGLs to Mont Belvieu and NGL 100% Port of Houston products to refineries and petrochemical companies Sorrento Near Baton Rouge to near 140 Delivers NGL products to refineries and 100% New Orleans petrochemical companies and Dixie Pipeline Chunchula Alabama/Florida border 117 Delivers NGLs to Petal Fractionator 100% to Petal, Mississippi Lake Charles/Bayport Mont Belvieu to Lake 134 Delivers high purity propylene from Mont 50% Propylene Pipeline Charles, Louisiana and Belvieu to Montell's Lake Charles and Bayport, Texas Bayport propylene plants and to Aristech's La Porte facility and receives refinery grade propylene from Mobil at Beaumont </TABLE> The Houston ship channel distribution system and the Sorrento system are bi-directional for maximum operating flexibility, market responsiveness and transportation efficiency. These systems transport feedstocks to the Company's facilities for processing and deliver products to petrochemical plants and refineries. The Houston ship channel distribution system has an aggregate 16
length of approximately 175 miles and extends west from Mont Belvieu, along the Houston ship channel to Pierce Junction south of Houston. The Houston ship channel system includes (i) a combination 6-inch and 8-inch propane/propylene mix pipeline; (ii) a combination 8-inch and 10-inch isobutane pipeline; (iii) an 8-inch methanol pipeline; and (iv) a combination 12-inch and 16-inch NGL import/export pipeline. The Houston ship channel distribution system serves the refinery and petrochemical industry concentrated along the Houston ship channel and connects the Mont Belvieu facilities to a number of the Company's major customers and suppliers. The Sorrento system comprises two pipeline subsystems aggregating 140 miles in length that originate from Sorrento, Louisiana and serve the major refineries and petrochemical companies on the Mississippi River from near Baton Rouge, Louisiana to near New Orleans, Louisiana. One subsystem is used for transporting propane, and one is used for transporting butane and natural gasoline. Propane received in the Sorrento system is delivered to petrochemical plants or into the Dixie Pipeline. Butane from Mont Belvieu is received from the Dixie Pipeline at the Company's Breaux Bridge storage facility, and transported through the Sorrento system to refineries. In January 1999, the Company announced the formation of a new joint venture, Entell NGL Services, LLC ("Entell"), for the development of a NGL transportation and distribution system. Entell anticipates that the system will be capable of distributing products from key NGL sources in southern Louisiana directly to major NGL markets, including the lower Mississippi River corridor, Dixie pipeline, Lake Charles, Louisiana and Mont Belvieu, Texas. Entell is equally owned by the Company and Tejas (a Shell subsidiary). Entell leases from the Company a portion of the Sorrento pipeline system connecting several market centers in Louisiana, including Breaux Bridge, Tebone, Riverside, Sorrento and Garyville. These assets have the capacity to move a total of 80,000 barrels per day. The Chunchula system originates at the Alabama-Florida border and extends west to the Company's NGL storage and fractionation facility in Petal, Mississippi. The Company owns and operates this 117-mile, 6-inch line consisting of the Chunchula Pipeline and the Jay Extension that gathers NGLs from the Chunchula, Jay and Hatters Pond Fields in Florida and Alabama for delivery to the Company's facility in Petal, Mississippi for processing or storage and further distribution. The Company operates a 134-mile propylene pipeline system which is used to distribute high purity propylene from Mont Belvieu to Montell's polypropylene plants in Lake Charles, Louisiana and Bayport, Texas and Aristech's facility in LaPorte, Texas. A segment of the pipeline is jointly owned by the Company and Montell, and another segment of the pipeline is jointly leased from Mobil. The Company is participating in pipeline joint ventures which will support its Baton Rouge NGL fractionator joint venture. The Tri-States Pipeline, a joint venture with Amoco, Duke Energy, Koch, Williams and Tejas (a Shell subsidiary), will extend approximately 169 miles from Mobile Bay, Alabama to near Kenner, Louisiana. The Wilprise Pipeline, a joint venture with Williams and Amoco, will extend approximately 30 miles from Kenner to Sorrento, Louisiana. Houston Ship Channel Import/Export Facility; Rail Cars and Facilities The Company leases and operates a NGL import/export facility at the Oiltanking Houston marine terminal on the Houston ship channel. The import/export facility is connected to Mont Belvieu via the Company's 16-inch bi-directional import/export pipeline. This pipeline enables NGL tankers to be offloaded at their maximum (10,000 barrels per hour) unloading rate, thus minimizing laytime and increasing the number of vessels that can be offloaded. An 8-inch methanol pipeline which is part of the Houston ship channel distribution system also extends from the facility to Mont Belvieu and enables methanol to be delivered by ship and then transferred to the MTBE facility. EPIK, a joint venture with Idemitsu, is constructing the NGL Product Chiller 17
for cooling NGL products for loading refrigerated marine tankers at the import/export facility. The NGL Product Chiller will speed the loading of tankers and increase export capability. The Company utilizes a fleet of approximately 350 rail cars under short and long-term leases used to deliver feedstocks to Mont Belvieu and transport NGL products throughout the United States. The Company also has rail loading/unloading facilities at Mont Belvieu, Texas, Breaux Bridge, Louisiana, and Petal, Mississippi to serve its own and customers' rail shipments. Competition The consumption of NGL products in the United States can be separated among four distinct markets. Petrochemical production provides the largest end-use market, followed by motor gasoline production, residential and commercial heating and agricultural uses. There are other hydrocarbon alternatives, primarily refined petroleum products, which can be substituted for NGL products in most end uses. In some uses, such as residential and commercial heating, a substitution of other hydrocarbon products for NGL products would require a significant expense or delay, but for other uses, such as the production of motor gasoline, ethylene, industrial fuels and petrochemical feedstocks, such a substitution can be readily made without significant delay or expense. Because certain NGL products compete with other refined petroleum products in the fuel and petrochemical feedstock markets, NGL product prices are set by or in competition with refined petroleum products. Increased production and importation of NGLs and NGL products in the United States may decrease NGL product prices in relation to refined petroleum alternatives and thereby increase consumption of NGL products as NGL products are substituted for other more expensive refined petroleum products. Conversely, a decrease in the production and importation of NGLs and NGL products could increase NGL product prices in relation to refined petroleum product prices and thereby decrease consumption of NGLs. However, because of the relationship of crude oil and natural gas production to NGL production, the Company believes any imbalance in the prices of NGLs and NGL products and alternative products would be temporary. Although competition for NGL product fractionation services is based primarily on the fractionation fee, the ability of a fractionator to obtain and distribute product is a function of the existence of the necessary pipelines and transportation facilities. A fractionator connected to an extensive transportation and distribution system has direct access to a larger market than its competitors. Overall, the Company believes it provides a broader range of services than any of its competitors at Mont Belvieu. In addition, the Company believes its joint venture relationships enable it to contract for the long-term utilization of a significant amount of its fractionation facilities with major producers and consumers of NGLs or NGL products. The Company's Mont Belvieu fractionation facility competes for volumes of mixed NGLs with three other fractionators at Mont Belvieu: a joint venture between Dynegy and Amoco (205,000 barrels per day capacity); Gulf Coast Fractionators, a joint venture of Conoco, Mitchell and Dynegy (110,000 barrels per day capacity); and a joint venture between Koch and Union Pacific Resources (110,000 barrels per day capacity). The Koch/Union Pacific Resources fractionator is scheduled for expansion to a capacity of 200,000 barrels per day in 1999. Mobil operates a fractionation facility (60,000 barrels per day capacity) in Hull, Texas that is connected to Mont Belvieu by pipeline and Phillips Petroleum operates a fractionation facility (70,000 barrels per day capacity) in Sweeny, Texas that is connected to Mont Belvieu by pipeline. Mobil and Phillips use their facilities primarily to process their own NGL production but at certain times these facilities compete with the fractionators at Mont Belvieu. The Company's fractionation facilities also compete on a more limited basis with two fractionators in Conway, Kansas: Williams (107,000 barrels per day capacity) and Koch (200,000 barrels per day capacity) and with a number of decentralized, smaller fractionation facilities in Louisiana, the most significant of which are Promix at Napoleonville (55,000 barrels per day capacity), Texaco/Williams at Paradis (45,000 barrels per day capacity) and TransCanada at Eunice and Riverside (45,000 barrels per day combined 18
capacity). In recent years, the Conway market has experienced excess capacity and prices for NGL products that are generally lower than prices at Mont Belvieu, although prices in Conway tend to strengthen along with demand for propane in winter months. Finally, a number of producers operate smaller-scale fractionators at individual field processing facilities. In the isomerization market, the Company competes primarily with Koch at Conway, Kansas; Enron at Riverside, Louisiana; and Conoco at Wingate, New Mexico. Enron and Valero also produce isobutane, primarily for internal production of MTBE. Competitive factors affecting isomerization operations include the price differential between normal butane and isobutane as well as the fees charged for isomerization services, long-term contracts, the availability of merchant capacity, the ability to produce a higher purity isobutane product and storage and transportation support. BEF competes with a number of MTBE producers, including a number of refiners who produce MTBE for internal consumption in the manufacture of reformulated motor gasoline. Competitive factors affecting MTBE production include production costs, long-term contracts, the availability of merchant capacity and federal and state environmental regulations relating to the content of motor gasoline. The Company competes with numerous producers of high purity propylene, which include many of the major refiners on the Gulf Coast. The Company and Ultramar Diamond Shamrock are the primary domestic commercial producers of high purity propylene from refinery-sourced propane/propylene mix. High purity propylene is also produced as a by-product from steam crackers used in ethylene production. Certain of the Company's competitors are major oil and natural gas companies and other large integrated pipeline or energy companies that have greater financial resources than the Company. The Company believes its independence from the major producers of NGLs and petrochemical companies is often an advantage in its dealings with its customers, but the Company's continued success will depend upon its ability to maintain strong relationships with the primary producers of NGLs and consumers of NGL products, particularly in the form of long-term contracts and joint venture relationships. Major Customers of the Company Although the Company's revenues are derived from a wide customer base, revenues from Montell, the largest single customer, accounted for approximately 13.8% of consolidated revenues in fiscal 1998. Montell owns a 45.4% undivided interest in one of the propylene fractionation units and the related pipeline system, and it leases such undivided interest in these facilities to the Company. For a more complete discussion of major customers in the last three fiscal years, see Note 7 of the Notes to the Consolidated Financial Statements. Significant Agreement with EPCO The Company has no employees. All management, administrative and operating functions are performed by employees of EPCO. Operating costs and expenses include charges for EPCO's employees who operate the Company's various facilities. Such charges are based upon EPCO's actual salary costs and related fringe benefits. In connection with the Company's initial public offering ("IPO") on July 27, 1998, EPCO, the General Partner and the Company entered into the EPCO Agreement pursuant to which (i) EPCO agreed to manage the business and affairs of the Company and the Operating Partnership; (ii) EPCO agreed to employ the operating personnel involved in the Company's business for which EPCO is reimbursed by the Company at cost; (iii) the Company and the Operating Partnership agreed to participate as named insureds in EPCO's current insurance program, and costs are allocated among the parties on the basis of formulas set forth in the agreement; (iv) EPCO agreed 19
to grant an irrevocable, non-exclusive worldwide license to all of the trademarks and trade names used in its business to the Company; (v) EPCO agreed to indemnify the Company against any losses resulting from certain lawsuits; and (vi) EPCO agreed to sublease all of the equipment which it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 rail cars to the Company for $1 per year and assigned its purchase options under such leases to the Company (hereafter referred to as "Retained Leases"). Pursuant to the EPCO Agreement, EPCO is reimbursed at cost for all expenses that it incurs in connection with managing the business and affairs of the Company, except that EPCO is not entitled to be reimbursed for any selling, general and administrative expenses. In lieu of reimbursement for such selling, general and administrative expenses, EPCO is entitled to receive an annual administrative services fee that initially equals $12.0 million. The General Partner, with the approval and consent of the Audit and Conflicts Committee of the Company, has the right to agree to increases in such administrative services fee of up to 10% each year during the 10-year term of the EPCO Agreement and may agree to further increases in such fee in connection with expansions of the Company's operations through the construction of new facilities or the completion of acquisitions that require additional management personnel. Employees At December 31, 1998, EPCO employed approximately 500 employees involved in the management and operation of assets owned and operated by the Company; none of whom were members of a union. Regulation Interstate Common Carrier Pipeline Regulation The Company's Chunchula and Lake Charles/Bayport pipelines are interstate common carrier oil pipelines subject to regulation by Federal Energy Regulatory Commission ("FERC") under the October 1, 1977 version of the Interstate Commerce Act ("ICA"). Standards for Terms of Service and Rates. As interstate common carriers, the Chunchula and Lake Charles/Bayport pipelines provide service to any shipper who requests transportation services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA requires the Company to maintain tariffs on file with the FERC that set forth the rates the Company charges for providing transportation services on the interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA gives the FERC authority to regulate the rates the Company charges for service on the interstate common carrier pipelines. The ICA requires, among other things, that such rates be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint. On October 24, 1992, Congress passed the Energy Policy Act of 1992 ("Energy Policy Act"). The Energy Policy Act deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act also limited the 20
circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party would have to show that it was previously contractually barred from challenging the rates or that the economic circumstances or the nature of the service underlying the rate had substantially changed or that the rate was unduly discriminatory or preferential. These grandfathering provisions and the circumstances under which they may be challenged have received only limited attention from the FERC, causing a degree of uncertainty as to their application and scope. The Energy Policy Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines, and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561, which, among other things, adopted a new indexing rate methodology for petroleum pipelines. Under the new regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling. Under Order No. 561, a pipeline must as a general rule utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. The Company believes the rates it charges for transportation service on its interstate pipelines have been grandfathered under the Energy Policy Act and are thus considered just and reasonable under the ICA. As discussed above, however, because of the uncertainty related to the application of the Energy Policy Act's grandfathering provisions to the Company's rates as well as the novelty and uncertainty related to the FERC's new indexing methodology, the Company is unable to predict what rates it will be allowed to charge in the future for service on its interstate common carrier pipelines. Furthermore, because rates charged for transportation must be competitive with those charged by other transporters, the rates set forth in the Company's tariffs will be determined based on competitive factors in addition to regulatory considerations. Allowance for Income Taxes in Cost of Service. In a 1995 decision regarding Lakehead Pipe Line Company ("Lakehead"), FERC ruled that an interstate pipeline owned by a limited partnership could not include in its cost of service an allowance for income taxes with respect to income attributable to limited partnership interests held by individuals. On request in 1996, FERC clarified that, in order to avoid any effect of a "curative allocation" of income from individual partners to the corporate partner, an allowance for income taxes paid by corporate partners must be based on income as reflected on the pipeline's books for earning and distribution rather than as reported for income tax purposes. Subsequent appeals of these rulings were resolved by a 1997 settlement among the parties and were never adjudicated. The effect of this policy on the Company is uncertain. The Company's rates are set using the indexing method and have been grandfathered. It is possible that a party might challenge the Company's grandfathered rates on the basis that the creation of the Company constituted a substantial change in circumstances, potentially lifting the grandfathering protection. Alternatively, a party might contend that, in light of the Lakehead ruling and creation of the Company, the Company's rates are not just and reasonable. While it is not possible to predict the likelihood that such challenges would succeed at FERC, if such challenges were to be raised and succeed, application of the Lakehead ruling would reduce the Company's permissible income tax allowance in any cost of service, and rates, to the extent income is attributable to partnership interests held by individual partners rather than corporations. Intrastate Common Carrier Regulation The Company's Houston ship channel pipeline is an intrastate private carrier not subject to rate regulation. The Sorrento pipeline is an intrastate common carrier pipeline that transports 21
NGL products and is subject to various Louisiana state laws and regulations that affect the terms of service and rates for such services. Other State and Local Regulation The Company's activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. Cogeneration The Company cogenerates electricity for internal consumption and heat for a process-related hot oil system at Mont Belvieu. If this electricity were sold to third parties, the Company's Mont Belvieu cogeneration facilities could be certified as qualifying facilities under the Public Utility Regulatory Policy Act of 1978 ("PURPA"). Subject to compliance with certain conditions under PURPA, this certification would exempt the Company from most of the regulations applicable to electric utilities under the Federal Power Act and the Public Utility Holding Company Act, as well as from most state laws and regulations concerning the rates, finances, or organization of electric utilities. However, since such electric power is consumed entirely by the Company's plant facilities, the Company's cogeneration activities are not subject to public utility regulation under federal or Texas law. Environmental Matters General. The operations of the Company are subject to federal, state and local laws and regulations relating to release of pollutants into the environment or otherwise relating to protection of the environment. The Company believes its operations and facilities are in general compliance with applicable environmental regulations. However, risks of process upsets, accidental releases or spills are associated with the Company's operations and there can be no assurance that significant costs and liabilities will not be incurred, including those relating to claims for damage to property and persons. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. The usual remedy for failure to comply with these laws and regulations is the assessment of administrative, civil and, in some instances, criminal penalties or, in rare circumstances, injunctions. The Company believes the cost of compliance with environmental laws and regulations will not have a material adverse effect on the results of operations or financial position of the Company. However, it is possible that the costs of compliance with environmental laws and regulations will continue to increase, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. In the event of future increases in costs, the Company may be unable to pass on those increases to its customers. The Company 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. Solid Waste. The Company currently owns or leases, and has in the past owned or leased, properties that have been used over the years for NGL processing, treatment, transportation and storage and for oil and natural gas exploration and production activities. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned by or leased by the Company during the operating history 22
of those facilities. In addition, a small number of these properties may have been operated by third parties over whom the Company 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. State and federal laws applicable to oil and natural gas wastes and properties have gradually become more strict and, pursuant to such laws and regulations, the Company could be required to remove or remediate previously disposed wastes or property contamination including groundwater contamination. The Company does not believe that there presently exists significant surface and subsurface contamination of the Company properties by hydrocarbons or other solid wastes. The Company generates both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. From time to time, the Environmental Protection Agency ("EPA") has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for such wastes. Furthermore, it is possible that some wastes generated by the Company 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. Such changes in the regulations may result in additional capital expenditures or operating expenses by the Company. Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. 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. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of its ordinary operations the Company will generate wastes that may fall within the definition of a "hazardous substance." The Company may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. The Company has not received any notification that it may be potentially responsible for cleanup costs under CERCLA. Clean Air Act--General. The operations of the Company are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were adopted in 1990 and contain provisions that may result in the imposition of certain pollution control requirements with respect to air emissions from the operations of the pipelines and the processing and storage facilities. For example, the Mont Belvieu processing and storage facility is located in the Houston-Galveston ozone non-attainment area, which is categorized as a "severe" area and, therefore, is subject to more restrictive regulations for the issuance of air permits for new or modified facilities. The Houston-Galveston area is among nine areas in the country in this "severe" category. One of the other consequences of this non-attainment status is the potential imposition of lower limits on the emissions of certain pollutants, particularly oxides of nitrogen which are produced through combustion, as in the gas turbines at the Mont Belvieu processing facility. Regulations imposing these new requirements on existing facilities will not be promulgated until the end of 2000, and, therefore, it is not possible at this time to assess the impact these requirements may have on the Company's operations. Failure to comply with these air statutes or the implementing regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. As part of the regular overall evaluation of its current operations, the Company is updating certain of its operating permits. The Company believes its operations, including its processing facilities, pipelines and storage facilities, are in substantial compliance with applicable air requirements. Clean Air Act--Fuels. To implement the Clean Air Act Amendments of 1990, the EPA, in November 1992, began requiring the use of motor gasoline containing 2.7% oxygen by weight during winter months in carbon monoxide non-attainment areas largely in the western half of the United States (approximately 25 metropolitan areas). Since January 1995, the EPA has required 23
the use of motor gasoline containing 2.0% oxygen by weight throughout the year in extreme and severe ozone non-attainment areas (nine metropolitan areas). The production of MTBE is driven by compliance with the requirements of these oxygenated fuels programs. Any changes to these programs that enable localities to opt out of these programs, lessen the requirements for oxygenates or favor the use of non-isobutane based oxygenated fuels would reduce demand for the Company's MTBE and could have a material adverse effect on the Company's results of operations. Several public advocacy and protest groups active in California and other states have asserted that MTBE contaminates water supplies, causes health problems and has not been as beneficial as originally contemplated in reducing air pollution. In California, state authorities negotiated an agreement with the EPA to implement a program requiring oxygenated motor gasoline at 2.0% for the whole state, rather than 2.7% only in selected areas. In addition, legislation to amend the Clean Air Act has been introduced in Congress to exempt California from the federal oxygenate requirements for reformulated motor gasoline. If this legislation is enacted, refiners could eliminate or reduce the amount of MTBE from motor gasoline sold in California as long as certain other minimum standards are met. This federal legislation is opposed by both the federal Department of Energy and the EPA. Many of the public advocacy and protest groups that have been campaigning for legislation to exempt California from the federal oxygenate requirement are also supporting a nationwide ban on the use of MTBE and other oxygenates, but no legislation to implement a nationwide ban has been introduced in Congress to date. Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws require containment of potential discharges of contaminants into federal and state waters. Regulations promulgated pursuant to these laws require that entities such as the Company that discharge into federal and state waters obtain National Pollutant Discharge Elimination System ("NPDES") and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws provide penalties for releases of unauthorized contaminants 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 stormwater runoff. The Company believes it will be able to obtain, or be included under, these Clean Water Act permits and that compliance with the conditions of such permits will not have a material effect on the Company. Underground Storage Requirements. The Company currently owns and operates underground storage caverns that have been created in naturally occurring salt domes in Texas, Louisiana and Mississippi. These storage caverns are used to store NGLs, NGL products, propane/propylene mix and propylene. Surface brine pits and brine disposal wells are used in the operation of the storage caverns. All of these facilities are subject to strict environmental regulation by state authorities under the Texas Natural Resources Code and similar statutes in Louisiana and Mississippi. Regulations implemented under such statutes address the operation, maintenance and/or abandonment of such underground storage facilities, pits and disposal wells, and require that permits be obtained. Failure to comply with the governing statutes or the implementing regulations may lead to the assessment of administrative, civil or criminal penalties. The Company believes its salt dome storage operations, including the caverns, brine pits and brine disposal wells, are in substantial compliance with applicable statutes. Safety Regulation The Company's pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended ("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. The Company believes its pipeline operations are in substantial compliance with applicable HLPSA requirements; however, 24
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 the Company's results of operations or financial position. The workplaces associated with the processing and storage facilities and the pipelines operated by the Company are also subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The Company believes it has operated in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. In general, the Company expects expenditures will increase in the future to comply with likely higher industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although the Company does not expect that such expenditures will have a material adverse effect on the Company. Title to Properties Real property held by the Company falls into two basic categories: (a) parcels that it owns in fee, such as the land at the Mont Belvieu complex and Petal fractionation and storage facility, and (b) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for Company operations. The fee sites upon which the major facilities are located have been owned by the Company or its predecessors in title for many years without any material challenge known to the Company relating to title to the land upon which the assets are located, and the Company believes it has satisfactory title to such fee sites. The Company has no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of- way or license held by it or to its title to any material lease, easement, right-of-way, permit or lease, and the Company believes it has satisfactory title to all of its material leases, easements, rights-of-way and licenses. Item 3. Legal Proceedings. EPCO has indemnified the Company against any litigation arising from events or actions prior to its formation. The Company is sometimes named as a defendant in litigation relating to its normal business operations. Although the Company insures itself against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify the Company against liabilities arising from future legal proceedings as a result of its ordinary business activity. Management is aware of no significant litigation, pending or threatened, that would have a significant adverse effect on the Company's financial position or results of operations. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to a vote of security holders during 1998. 25
PART II Item 5. Market for the Registrant's Common Equity and Related Unitholder Matters. The following table sets forth the high and low sale prices per Common Unit (as reported under the symbol "EPD" on the New York Stock Exchange), the amount of cash distributions paid per Common Unit and the declaration and payment dates related to such cash distributions. The Common Units began trading on July 28, 1998. <TABLE> <CAPTION> Cash Distributions ------------------ Price Range Distribution Declaration Payment High Low Amount Date Date ---- --- ------ ---- ---- <S> <C> <C> <C> <C> <C> 1998 - ---- Third Quarter $22.063 $14.625 - - - Fourth Quarter $18.375 $13.750 $0.32 October 30,1998 November 12, 1998 1999 - ---- First Quarter $18.500 $14.938 $0.45 January 29, 1999 February 11, 1999 (through March 1, 1999) </TABLE> The Company pays a minimum quarterly distribution of $.45 per Common Unit. Although the payment of the minimum quarterly distribution is not guaranteed, the Company currently expects that it will continue to pay comparable cash distributions in the future. The $.32 cash distribution made during the fourth quarter of 1998 was based upon the minimum quarterly distribution of $0.45 per Unit adjusted to take into account the 65-day period of the third quarter during which the Company was a public entity. As of March 1, 1999, there were approximately 120 Unitholders of record of the Company's Common Units. 26
Item 6. Selected Financial Data. The following table sets forth for the periods and at the dates indicated, selected historical financial data for the Company. The selected historical financial data (except for EBITDA of unconsolidated affiliates) have been derived from the Company's audited financial statements for the periods indicated. The selected historical income statement data for each of the three years in the period ended December 31, 1998 and the selected balance sheet data as of December 31, 1998 and 1997 should be read in conjunction with the audited financial statements for such periods included elsewhere in this report. EBITDA of unconsolidated affiliates has been derived from the audited financial statements of such entities for the periods indicated. See also "Management's Discussion and Analysis of Financial Condition and Results of Operation." The dollar amounts in the table below, except per Unit data, are in thousands. <TABLE> <CAPTION> For Year Ended December 31, 1994 1995 1996 1997 1998 <S> <C> <C> <C> <C> <C> Income Statement Data: Revenues $586,609 $790,080 $999,506 $1,020,281 $738,902 Operating costs and expenses (1) 534,783 727,337 907,524 938,237 686,160 ---------------------------------------------------------- Operating margin 51,826 62,743 91,982 82,044 52,742 Selling, general and administrative expenses (1,2) 16,972 21,120 23,070 21,891 18,216 ---------------------------------------------------------- Operating income 34,854 41,623 68,912 60,153 34,526 Interest expense (25,411) (27,567) (26,310) (25,717) (14,696) Interest income 2,477 554 2,705 1,934 1,581 Equity in income of unconsolidated affiliates 7,257 12,274 15,756 15,682 15,671 Gain (loss) on sale of assets 4,271 7,948 - (155) 276 Other income (expense), net 45 305 364 793 (3) ---------------------------------------------------------- Income before extraordinary charge and minority interest 23,493 35,137 61,427 52,690 37,355 Extraordinary item - early extinguishment of debt - - - - (27,176) ---------------------------------------------------------- Income before minority interest 23,493 35,137 61,427 52,690 10,179 Minority interest (235) (351) (614) (527) (102) ---------------------------------------------------------- Net income $ 23,258 $ 34,786 $ 60,813 $ 52,163 $ 10,077 ========================================================== Net income per Unit (3) $ 0.42 $ 0.63 $ 1.10 $ 0.94 $ 0.17 Dividends declared per Unit $ 0.32 Balance Sheet Data (at period end): Total assets $573,348 $610,931 $711,151 $ 697,713 $741,037 Long-term debt 268,585 281,656 255,617 230,237 90,000 Consolidated equity / Partners' equity 189,366 198,815 266,021 311,885 562,536 Other Financial Data: Cash flows from operating activities $ 49,997 $ 12,212 $ 91,431 $ 57,795 $(20,294) Cash flows from investing activities (36,944) (9,233) (57,725) (30,982) (50,695) Cash flows from financing activities (21,973) 11,995 (24,930) (26,551) 61,238 EBITDA (4) 55,430 65,406 87,109 79,882 55,472 EBITDA of unconsolidated affiliates (5) 7,198 18,520 25,012 24,372 23,912 </TABLE> Notes - ----- (1) Certain 1994 through 1997 amounts have been reclassified to conform to the 1998 presentation (2) 1998 expenses are lower than 1997 amounts due to the adoption of the EPCO agreement (3) Net income per Unit is computed by dividing the limited partners' 99% interest in Net income by the weighted average of the number of Units outstanding. The weighted average number of Units outstanding from 1994 through 1997 was 54.963 million. For 1998, the weighted average number of Units outstanding was 60.124 million. (4) EBITDA is defined as net income plus depreciation and amortization and interest expense less equity in income of unconsolidated affiliates. EBITDA should not be considered as an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with generally accepted accounting principals. EBITDA is not intended to represent cash flow and does not represent the measure of cash available for distribution, but provides additional information for evaluating the Company's ability to make the minimum quarterly distribution. Management uses EBITDA to assess the viability of projects and to determine overall rate of returns on alternative investment opportunities. Because EBITDA excludes some, but not all, items that affect net income and this (Notes continued on following page) 27
measure may vary among companies, the EBITDA data presented above may not be comparable to similarly titled measures of other companies. EBITDA for 1998 excludes the extraordinary charge of $27.176 million related to the early extinguishment of debt. (5) Represents the Company's pro rata share of net income plus depreciation and amortization and interest expense of the unconsolidated affiliates. Since the purchase of the Company's pro rata share of bank debt of BEF and MBA in July 1998, EBITDA of unconsolidated affiliates has closely approximated the aggregate cash that the Company will receive from its investment in BEF and MBA. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation. Industry Environment Because certain NGL products compete with other refined petroleum products in the fuel and petrochemical feedstock markets, NGL product prices are set by or in competition with refined petroleum products. Increased production and importation of NGLs and NGL products in the United States may decrease NGL product prices in relation to refined petroleum alternatives and thereby increase consumption of NGL products as NGL products are substituted for other more expensive refined petroleum products. Conversely, a decrease in the production and importation of NGLs and NGL products could increase NGL product prices in relation to refined petroleum product prices and thereby decrease consumption of NGLs. However, because of the relationship of crude oil and natural gas production to NGL production, the Company believes any imbalance in the prices of NGLs and NGL products and alternative products would be temporary. Historically, when the price of crude oil is a multiple of ten or more to the price of natural gas (i.e., crude oil $20 per barrel and natural gas $2 per thousand cubic feet ("MCF")), NGL pricing has been strong due to increased use in manufacturing petrochemicals. In 1998, the industry experienced an annualized multiple of approximately six (i.e., crude oil $12 per barrel and natural gas $2 per MCF), which caused petrochemical manufacturing demand to change from reliance on NGLs to a preference for crude oil derivatives. This change resulted in the lowering of both the production and pricing of NGLs. In the NGL industry, revenues and cost of goods sold can fluctuate significantly up or down based on current NGL prices. However, operating margins will generally remain constant except for the effect of inventory price adjustments or increased operating expenses. The following discussion of the historical financial condition and results of operations of the Company should be read in conjunction with the Company's historical consolidated financial statements and the notes thereto included elsewhere in this report. NGL Fractionation The profitability of this business unit depends on the volume of mixed NGLs that the Company processes for its toll customers and the level of toll processing fees charged to its customers. The most significant variable cost of fractionation is the cost of energy required to operate the units and to heat the mixed NGLs to effect separation of the NGL products. The Company is able to reduce its energy costs by capturing excess heat and re-using it in its operations. Additionally, the Company's NGL fractionation processing contracts typically contain escalation provisions for cost increases resulting from increased variable costs, including energy costs. The Company's interest in the operations of its NGL fractionation facilities at Mont Belvieu consists of a directly-owned 12.5% undivided interest and a 49.0% economic interest in MBA, which in turn owns a 50.0% undivided interest in such facilities. The Company's 12.5% interest is recorded as part of revenues and expenses, and its effective 24.5% economic interest is recorded as an equity investment in an unconsolidated subsidiary. 28
Isomerization The profitability of this business unit depends on the volume of normal butane that the Company isomerizes (i.e., converts) into isobutane for its toll processing customers, the level of toll processing fees charged to its customers, and the margins generated from selling isobutane to merchant customers. The Company's toll processing customers pay the Company a fee for isomerizing their normal butane into isobutane. In addition, the Company sells isobutane that it obtains by isomerizing normal butane into isobutane, fractionating mixed butane into isobutane and normal butane, or purchasing isobutane in the spot market. The Company determines the optimal sources for isobutane to meet sales obligations based on current and expected market prices for isobutane and normal butane, volumes of mixed butane held in inventory, and estimated costs of isomerization and mixed butane fractionation. The Company purchases most of its imported mixed butanes between the months of February and October. During these months, the Company is able to purchase imported mixed butanes at prices that are often at a discount to posted market prices. Because of its storage capacity, the Company is able to store these imports until the summer months when the spread between isobutane and normal butane typically widens or until winter months when the prices of isobutane and normal butane typically rise. As a result, inventory investment is generally at its highest level at the end of the third quarter of the year. Should this spread not materialize, or in the event absolute prices decline, margins generated from selling isobutane to merchant customers may be negatively affected. Propylene Fractionation The profitability of this business unit depends on the volumes of refinery- sourced propane/propylene mix that the Company processes for its toll customers, the level of toll processing fees charged to its customers and the margins associated with buying refinery-sourced propane/propylene mix and selling high purity propylene to meet sales contracts with non-tolling customers. Pipelines The Company operates both interstate and intrastate NGL product and propylene pipelines. The Company's interstate pipelines are common carriers and must provide service to any shipper who requests transportation services at rates regulated by the FERC. One of the Company's intrastate pipelines is a common carrier regulated by the State of Louisiana. The profitability of this business unit is primarily dependent on pipeline throughput volumes. Unconsolidated Affiliates At December 31, 1998, the Company's unconsolidated affiliates were BEF, MBA, EPIK, BRF, Tri-States and Wilprise. BEF owns the MTBE production facility operated by the Company at its Mont Belvieu complex. MBA owns a 50% interest in a NGL fractionation facility at the Company's Mont Belvieu complex. EPIK owns a refrigerated NGL marine terminal loading facility located on the Houston ship channel. An expansion of EPIK's NGL marine terminal loading facility is underway and is scheduled for completion in the fourth quarter of 1999. BRF owns a NGL fractionation facility which is under construction in Louisiana. This facility is expected to begin operations in the second quarter of 1999. Tri-States owns a NGL pipeline which is under construction in Louisiana, Mississippi, and Alabama. Wilprise owns a NGL pipeline which is under construction in Louisiana. Management anticipates that both the Tri-States and Wilprise pipelines will be operational in the second quarter of 1999. 29
Prepayment Penalties on Extinguishment of Debt The Company incurred a $27.2 million extraordinary loss during the third quarter of 1998 in connection with the early extinguishment of debt assumed from EPCO in connection with the IPO. The extraordinary loss was equal to remaining unamortized debt origination costs associated with such debt and make-whole premiums payable in connection with the repayment of such debt. Results of Operations of the Company The Company's operating margins by business unit (in thousands) over the past three years were as follows: Year Ended December 31, 1996 1997 1998 --------------------------------- Operating Margin: NGL Fractionation $ 1,982 $ 2,801 $ 3,743 Isomerization 51,068 38,286 17,540 Propylene Fractionation 18,260 18,996 11,275 Pipeline 11,270 13,520 14,121 Storage and Other Plants 9,402 8,441 6,063 --------------------------------- Total $91,982 $82,044 $52,742 ================================= The Company's plant production (in thousands of barrels per day) over the past three years was as follows: Year Ended December 31, 1996 1997 1998 --------------------------------- Plant Production Data: NGL Fractionation 166 189 191 Isomerization 71 67 67 MTBE 13 14 14 Propylene Fractionation 16 26 26 The Company's equity in income of unconsolidated affiliates (in thousands) over the past three years was as follows: Year Ended December 31, 1996 1997 1998 --------------------------------- Equity in income of unconsolidated affiliates: BEF $ 9,752 $ 9,305 $ 9,801 MBA 6,004 6,377 5,213 EPIK - - 748 BRF - - (91) --------------------------------- Total $15,756 $15,682 $15,671 ================================ Year Ended December 31, 1998 Compared with Year Ended December 31, 1997 Revenues; Costs and Expenses The Company's revenues decreased by 27.6% to $738.9 million in 1998 compared to $1,020.3 million in 1997. The Company's costs and operating expenses decreased by 26.9% to $686.2 million in 1998 compared to $938.2 million in 1997. Both revenues and cost of goods sold decreased dramatically from 1997 to 1998 due to sharp declines in average NGL prices during most of 1998. For example, isobutane prices decreased from an average of 46.9 cents per gallon in 1997 to 32.1 cents per gallon in 1998. Operating margin decreased by 35.7% to $52.7 million in 1998 from $82.0 million in 1997. The reduced operating margin in 1998 is mainly due to the effect of declining NGL prices on inventory values and merchant activities during 1998. NGL Fractionation. The Company's operating margin for NGL fractionation increased by 33.6% to $3.7 million in 1998 from $2.8 million in 1997. Excluding the positive effect of $1.3 30
million in overhead expenses and support facility cost reimbursements from joint venture partners for 1998, the Company's NGL fractionation operating margin decreased 14.3% to $2.4 million from $2.8 million in 1997. The operating margin for NGL fractionation declined by $1.9 million in 1998 due to lower toll processing fees. On average, these fees were 2.3 cents per gallon in 1997 versus 2.1 cents per gallon in 1998. The decline was partially offset by lower operating expenses. Average daily fractionation volumes increased from 189,323 barrels per day in 1997 to 191,176 barrels per day in 1998, primarily as a result of increased volumes from joint owners' new gas processing plants which began operations during 1998. Isomerization. The Company's operating margin for isomerization decreased by 54.2% to $17.6 million in 1998 from $38.3 million in 1997. This was a direct result of inventory write-downs, loss of marketing profits due to lower butane price spreads, and the decline of isomerization revenues on merchant activities. The difference between the average prices of isobutane and normal butane decreased from 3.3 cents per gallon for 1997 to 1.1 cents per gallon for 1998 as a result of the preference for crude-oil-derivative petrochemical feedstocks as described above. Propylene Fractionation. The Company's operating margin for propylene fractionation decreased by 40.6% to $11.3 million in 1998 from $19.0 million in 1997. The decrease in operating margin was a direct result of continued falling prices of high purity and refinery grade propylene, reduced production volumes and write-downs of feedstock inventory. Production volumes decreased from 26,456 barrels per day in 1997 to 25,625 barrels per day in 1998. Pipeline. The Company's operating margin for pipeline operations increased by 4.4% to $14.1 million in 1998 from $13.5 million in 1997, reflecting a 10.0% increase in throughput volume due primarily to increased butane imports. Selling, General and Administrative Expenses Selling, general and administrative expenses decreased by $3.7 million to $18.2 million in 1998 from $21.9 million in 1997. This decrease was primarily due to the adoption of the EPCO Agreement in July 1998 in conjunction with the IPO which fixed reimbursable selling, general, and administrative expenses at $1.0 million per month. Interest Expense Interest expense was $14.7 million in 1998 and $25.7 million in 1997. The $11.0 million decline was due to a decrease in the average debt outstanding during the first seven months of 1998 as compared to the same period of 1997, and the prepayment of debt in conjunction with the IPO in July 1998. Equity Income of Unconsolidated Affiliates Equity income of unconsolidated affiliates remained constant at $15.7 million in 1998 and 1997. Equity income in BEF increased by 5.4% to $9.8 million in 1998 from $9.3 million in 1997 due primarily to lower interest costs. Equity income in MBA decreased by 18.7% to $5.2 million in 1998 from $6.4 million in 1997 due to lower average NGL fractionation processing fees. Among the Company's new projects, equity income in EPIK for 1998 was $0.8 million. Year Ended December 31, 1997 Compared with Year Ended December 31, 1996 Revenues; Costs and Expenses The Company's revenues increased by 2.1% to $1,020.3 million in 1997 compared to $999.5 million in 1996. The Company's costs and operating expenses increased by 3.4% to $938.2 31
million in 1997 compared to $907.5 million in 1996. Operating margin decreased by 10.8% to $82.0 million in 1997 from $92.0 million in 1996. NGL Fractionation. The Company's operating margin for NGL fractionation increased by 41.3% to $2.8 million in 1997 from $2.0 million in 1996. The increase was due primarily to the phase-in of a 45,000 barrel per day expansion in the capacity of the NGL fractionation facilities at Mont Belvieu resulting in increased NGL fractionation volumes in the second half of 1997, principally from the joint owners of the facility, and increases in fractionation fees as a result of higher natural gas and electricity costs that resulted in contractual escalations in pricing formulas. Isomerization. The Company's operating margin for isomerization decreased by 25.0% to $38.3 million in 1997 from $51.1 million in 1996. The Company's margins were negatively impacted by decreases in marketing margins which declined as a result of lower isobutane prices after the first quarter of 1997 and a lower average spread between isobutane and normal butane prices. Isobutane prices were unusually high in the second half of 1996 and the first quarter of 1997. In addition, isomerization processing margins decreased due to the loss of a processing contract from a significant customer and lower utilization of the deisobutanizer units as a result of lower import volume of mixed butanes. Propylene Fractionation. The Company's operating margin for propylene fractionation increased by 4.0% to $19.0 million in 1997 from $18.3 million in 1996. Propylene fractionation operating margins were positively affected by an increase in volumes due to the start up of the Company's second propylene fractionation unit in April 1997. This increase in volume was largely offset by price decreases for high purity propylene in the fourth quarter of 1997, which reflected weaker prices for polypropylene, compared to price increases for high purity propylene in late 1996. The Company uses an average cost method of accounting for its refinery-sourced propane/propylene mix feedstock costs. Accordingly, the Company's feedstock costs generally increase or decrease at a slower rate than high purity propylene market prices. Pipeline. The Company's operating margin for pipeline operations increased by 20.0% to $13.5 million in 1997 from $11.3 million in 1996, reflecting an 11.5% increase in throughput volume. Selling, General and Administrative Expenses Selling, general and administrative expenses decreased by $1.2 million to $21.9 million in 1997 from $23.1 million in 1996. This decrease was primarily due to the recognition of compensation expense in 1996 related to employee stock appreciation rights ("SAR"). SAR expense declined to $1.1 million in 1997 compared to $2.1 million in 1996. EPCO retained the liability for all outstanding SARs following the IPO. Interest Expense Interest expense was $25.7 million in 1997 and $26.3 million in 1996. The $0.6 million decrease was due to a decrease in the average debt outstanding to $243.8 million in 1997 from $268.4 million in 1996. Equity Income of Unconsolidated Affiliates Equity income of unconsolidated affiliates includes amounts from BEF and MBA. Earnings attributable to BEF were $9.3 million in 1997 and $9.8 million in 1996. Earnings attributable to MBA were $6.4 million in 1997 and $6.0 million in 1996, reflecting increased NGL fractionation volumes in the second half of 1997. 32
Liquidity and Capital Resources General The Company's primary cash requirements, in addition to normal operating expenses, are debt service, maintenance capital expenditures, expansion capital expenditures, and quarterly distributions to the partners. The Company expects to fund future cash distributions and maintenance capital expenditures with cash flows from operating activities. Expansion capital expenditures for current projects are expected to be funded with working capital and borrowings under the revolving bank credit facility described below while capital expenditures for future expansion activities are expected to be funded with cash flows from operating activities and borrowings under the revolving bank credit facility. Cash flows from operating activities were a $20.3 million outflow for 1998 as compared to $57.8 million inflow for the comparable period of 1997. Cash flows from operating activities primarily reflect the effects of net income, depreciation and amortization, extraordinary items, equity income of unconsolidated affiliates and changes in working capital. Depreciation and amortization increased by $1.5 million in 1998 as a result of additional capital expenditures. The net effect of changes in operating accounts from year to year is generally the result of timing of NGL sales and purchases near the end of the period. Cash outflows from investing activities were $50.7 million in 1998 and $31.0 million for the comparable period of 1997. Cash outflows included capital expenditures which aggregated $8.4 million (including approximately $7.7 million of maintenance capital expenditures) for 1998 and $33.6 million for 1997. Investing cash outflows also included $26.8 million in contributions to unconsolidated affiliates that were primarily used for construction projects during 1998. The Company purchased $33.7 million in notes receivable from BEF and MBA which is included as a cash outflow from investing activities and received $7.2 million in payments on these notes included as a cash inflow from investing activities during 1998. Cash flows from financing activities were a $61.2 million inflow in 1998 and a $26.6 million outflow for the comparable period of 1997. Cash flows from financing activities during 1998 were affected primarily by repayments of long- term debt, borrowings under long-term debt agreements, costs for early extinguishment of debt, distributions to the Unitholders, and net proceeds from the sale of partnership Units in connection with the IPO. Future Capital Expenditures The Company currently estimates that its share of remaining expenditures for significant capital projects in fiscal 1999 will be approximately $29.1 million. These expenditures will be for the construction of new joint venture projects in Louisiana which will be recorded as additional investments in unconsolidated subsidiaries. The Company expects to finance these expenditures out of operating cash flows, the proceeds from its IPO and borrowings under its bank credit facility. As of December 31, 1998, the Company had $11.1 million in outstanding purchase commitments associated with its capital projects. Distributions from Unconsolidated Affiliates; Loan Participations Distributions to the Company from MBA were $5.7 million for 1998 and $7.3 million in 1997. Distributions from BEF in 1998 were $2.4 million. Prior to the first quarter of 1998, BEF was prohibited under the terms of its bank indebtedness from making distributions to its owners. These restrictions lapsed during the first quarter of 1998 as a result of BEF having repaid 50% of the principal on such indebtedness, and the Company received its first distribution from BEF in April 1998. 33
In connection with the IPO, the Company purchased participation interests in a bank loan to MBA and a bank loan to BEF. The Company acquired an approximate $7.7 million participation interest in the bank debt of MBA, which bears interest at a floating rate per annum of LIBOR plus 0.75% and matures on December 31, 2001. The Company will receive monthly principal payments, aggregating approximately $1.7 million per year, plus interest from MBA during the term of the loan. The Company will receive a final payment of principal of $1.8 million upon maturity. The Company acquired an approximate $26.1 million participation interest in a bank loan to BEF, which bears interest at a floating rate per annum at either the bank's prime rate, CD rate, or the Eurodollar rate plus the applicable margin as defined in the facility and matures on May 31, 2000. The Company will receive quarterly principal payments of approximately $3.3 million plus interest from BEF during the term of the loan. Bank Credit Facility In connection with the IPO, the Company entered into a $200.0 million bank credit facility that includes a $50.0 million working capital facility and a $150.0 million revolving term loan facility. The $150.0 million revolving term loan facility includes a sublimit of $30.0 million for letters of credit. As of December 31, 1998, the Company has borrowed $90.0 million under the revolving term loan facility. The Company's obligations under the bank credit facility are unsecured general obligations and are non-recourse to the General Partner. Borrowings under the bank credit facility will bear interest at either the bank's prime rate or the Eurodollar rate plus the applicable margin as defined in the facility. The Company elects the basis for the interest rate at the time of each borrowing. Interest rates ranged from 6.25% to 6.69% during 1998, and the weighted-average interest rate at December 31, 1998 was 6.45%. The bank credit facility will expire after two years and all amounts borrowed thereunder shall be due and payable on such date. There must be no amount outstanding under the working capital facility for at least 15 consecutive days during each fiscal year. The credit agreement relating to the facility contains a prohibition on distributions on, or purchases or redemptions of, Units if any event of default is continuing. In addition, the bank credit facility contains various affirmative and negative covenants applicable to the ability of the Company to, among other things, (i) incur certain additional indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) make investments, (v) engage in transactions with affiliates and (vi) enter into a merger, consolidation or sale of assets. The bank credit facility requires that the Operating Partnership satisfy the following financial covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined in the bank credit facility) of at least $257,000,000 plus 75% of the net cash proceeds from the sale of equity securities of the Company that are contributed to the Operating Partnership, (ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense (as defined in the bank credit facility) for the previous 12-month period of at least 3.50 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more than 2.25 to 1.0. A "Change of Control" constitutes an Event of Default under the bank credit facility. A Change of Control includes any of the following events: (i) Dan L. Duncan (and certain affiliates) cease to own (a) at least 51% (on a fully converted, fully diluted basis) of the economic interest in the capital stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own, through a wholly owned subsidiary, at least 95% of the outstanding membership interest in the General Partner and at least 51% of the outstanding Common Units; (iii) any person or group beneficially owns more than 20% of the outstanding Common Units; (iv) the General Partner ceases to be the general partner of the Company or the Operating Partnership; or (v) the Company ceases to be the sole limited partner of the Operating Partnership. 34
Year 2000 Readiness Disclosure Pursuant to the EPCO Agreement, any selling, general and administrative expenses related to Year 2000 compliance issues are covered by the annual administrative services fee paid by the Company to EPCO. Consequently, only those costs incurred in connection with Year 2000 compliance which relate to operational information systems and hardware will be paid directly by the Company. Since 1997, EPCO has been assessing the impact of Year 2000 compliance issues on the software and hardware used by the Company. A team is in the process of reviewing and documenting the status of EPCO's and the Company's systems for Year 2000 compliance. The key information systems under review include EPCO's financial and human resource systems and the Company's pipeline Supervisory Control and Data Acquisition ("SCADA") system, plant, storage, and other pipeline operating systems. In connection with each of these areas, consideration is being given to hardware, operating systems, applications, data base management, system interfaces, electronic transmission, and outside vendors. As of December 31, 1998, EPCO had spent approximately $12,000 in connection with Year 2000 compliance and has estimated the future costs to approximate $340,000. This cost estimate does not include internal costs of EPCO's previously existing resources and personnel that might be partially used for Year 2000 compliance or cost of normal system upgrades which also included various Year 2000 compliance features or fixes. Such internal costs have been determined to be materially insignificant to the total estimated cost of Year 2000 compliance. At this time, the Company believes its total cost for known or anticipated remediation of its information systems to make them Year 2000 compliant will not be material to its financial position or its ability to sustain operations. Since the IPO date, the Company has incurred substantially no expenditures in connection with Year 2000 compliance. However, the Company expects future spending to approximate $1,026,000 (principally for the SCADA system) to complete the project and become fully compliant with all Year 2000 issues. This estimated cost does not include the Company's internal costs related to previously existing resources and personnel that might be partially used for remediation of Year 2000 compliance issues. Such internal costs have been determined to be materially insignificant to the total estimated cost of Year 2000 compliance. These amounts are current cost estimates and actual future costs could potentially be higher or lower than the estimates. The Company relies on third-party suppliers for certain systems, products and services, including telecommunications. There can be no assurance that the systems of other companies on which the Company's systems rely also will timely be compliant or that any such failure to be compliant by another company would not have an adverse effect on the Company's systems. The Company has received some preliminary information concerning Year 2000 compliance status from a group of critical suppliers and vendors, and anticipates receiving additional information in the near future. This information will assist the Company in determining the extent to which it may be vulnerable to those third parties' failure to address their Year 2000 compliance issues. Management believes it has a program to address the Year 2000 compliance issue in a timely manner. Completion of the plan and testing of replacement or modified systems is anticipated during the third quarter of 1999. Nevertheless, since it is not possible to anticipate all possible future outcomes, especially when third parties are involved, there could be circumstances in which the Company would be unable to invoice customers or collect payments. The failure to correct a material Year 2000 compliance problem could result in an interruption in or failure of certain normal business activities or operations of the Company. Such failures could have a material adverse effect on the Company. The amount of potential liability and lost revenue has not been estimated. The Company is continuing its work on contingency plans to address unavoided or unavoidable risks associated with Year 2000 compliance issues. 35
Accounting Standards Recent Statements of Financial Accounting Standards ("SFAS") include (effective for all fiscal quarters of fiscal years beginning after June 15, 1999) SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Management is currently studying this SFAS item for its possible impact on the consolidated financial statements. On April 3, 1998, the American Institute of Certified Public Accountants issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up Activities." For years beginning after December 15, 1998, SOP 98-5 generally requires that all start-up costs of a business activity be charged to expense as incurred and any start-up costs previously deferred should be written off as a cumulative effect of a change in accounting principle. Based on its assessment of SOP 98-5, management believes SOP 98-5 will not have a material impact on the financial statements except for a $4.5 million noncash write-off at January 1, 1999 of the unamortized balance of deferred start-up costs of BEF, in which the Company owns a 33-1/3% interest. This write-off will cause a $1.5 million reduction in the equity in income of unconsolidated affiliates for 1999 and a corresponding reduction in the Company's investment in unconsolidated affiliates. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company is exposed to financial market risks, including changes in interest rates with respect to its investments in financial instruments and changes in commodity prices. The Company may, but generally does not, use derivative financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) or derivative commodity instruments (i.e., commodity futures, forwards, swaps, or options, and other commodity instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument) to mitigate either of these risks. The return on the Company's financial investments is generally not affected by foreign currency fluctuations. The Company does not use derivative financial instruments for speculative purposes. At December 31, 1998, the Company had no derivative instruments in place to cover any potential interest rate, foreign currency or other financial instrument risk. At December 31, 1998, the Company had $24.1 million invested in cash and cash equivalents. All cash equivalent investments other than cash are highly liquid, have original maturities of less than three months, and are considered to have insignificant interest rate risk. The Company's inventory of NGLs and NGL products at December 31, 1998, was $17.6 million. Inventories are carried at the lower of cost or market. A 10% adverse change in commodity prices would result in an approximate $1.7 million decrease in the fair value of the Company's inventory, based on a sensitivity analysis at December 31, 1998. Actual results may differ materially. All the Company's long-term debt is at variable interest rates; a 10% change in the base rate selected would have an approximate $0.6 million effect on the amount of interest expense for the year based upon amounts outstanding at December 31, 1998. Item 8. Financial Statements and Supplementary Data. The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure. None. 36
PART III Item 10. Directors and Executive Officers of the Registrant. Company Management The General Partner manages and operates the activities of the Company. Notwithstanding any limitation on its obligations or duties, the General Partner is liable, as the general partner of the Company, for all debts of the Company (to the extent not paid by the Company), except to the extent that indebtedness or other obligations incurred by the Company are made specifically non-recourse to the General Partner. Whenever possible, the General Partner intends to make any such indebtedness or other obligations non-recourse to the General Partner. At least two of the members of the Board of Directors of the General Partner who are neither officers, employees or security holders of the General Partner nor directors, officers, employees or security holders of any affiliate of the General Partner serve on the Audit and Conflicts Committee, which has the authority to review specific matters as to which the Board of Directors believes there may be a conflict of interests in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Company. Any matters approved by the Audit and Conflicts Committee are conclusively deemed to be fair and reasonable to the Company, approved by all partners of the Company and not a breach by the General Partner or its Board of Directors of any duties they may owe the Company or the Unitholders. In addition, the Audit and Conflicts Committee reviews the external financial reporting of the Company, recommends engagement of the Company's independent public accountants, reviews the Company's procedures for internal auditing and the adequacy of the Company's internal accounting controls and approves any increases in the administrative service fee payable under the EPCO Agreement. As is commonly the case with publicly-traded limited partnerships, the Company does not directly employ any of the persons responsible for managing or operating the Company. In general, the management of EPCO, the majority-owner of the General Partner, manages and operates the Company's business pursuant to the EPCO Agreement. Directors and Executive Officers of the General Partner Set forth below is the name, age, and position of each of the directors and executive officers of the General Partner. Each director and officer is elected for a one-year term. Name Age Position with General Partner - --------------------------- --- ------------------------------------------------ Dan L. Duncan 65 Director and Chairman of the Board O.S. Andras 63 Director, President, and Chief Executive Officer Randa L. Duncan 37 Director and Group Executive Vice President Gary L. Miller 50 Director, Executive Vice President, Chief Financial Officer, and Treasurer Dr. Ralph S. Cunningham (1) 58 Director Lee W. Marshall, Sr.(1) 66 Director Albert W. Bell 60 Executive Vice President, Business Management William D. Ray 63 Executive Vice President, Marketing and Supply Charles E. Crain 65 Senior Vice President, Operations Michael R. Johnson 54 General Counsel and Secretary - ------------- (1) Member of Audit and Conflicts Committee Dan L. Duncan was elected as Chairman of the Board and a Director of the General Partner in April 1998. Mr. Duncan joined EPCO in 1969 and has served as Chairman of the Board of EPCO since 1979. He served as President of EPCO from 1970 to 1979 and Chief Executive Officer from 1982 to 1985. 37
O. S. Andras was elected as President, Chief Executive Officer and a Director of the General Partner in April 1998. Mr. Andras has served as President and Chief Executive Officer of EPCO since 1996. Mr. Andras served as President and Chief Operating Officer of EPCO from 1982 to 1996 and Executive Vice President of EPCO from 1981 to 1982. Before joining EPCO, he was employed by The Dow Chemical Company in various capacities from 1960 to 1981, including Director of Hydrocarbons. Mr. Andras also serves as a director of Tetra Technologies, Inc. Randa L. Duncan was elected as Group Executive Vice President and a director of the General Partner in April 1998. Ms. Duncan has served as Group Executive Vice President of EPCO since 1994. Before joining EPCO, she was an attorney with the firms of Butler & Binion from 1988 to 1991 and Brown, Sims, Wise and White from 1991 until 1994. Ms. Duncan is the daughter of Dan L. Duncan. Albert W. Bell was elected as Executive Vice President, Business Management of the General Partner in April 1998. Mr. Bell has served as Executive Vice President, Business Management of EPCO since 1994. Mr. Bell joined EPCO in 1980 as President of its Canadian subsidiary. Mr. Bell transferred to EPCO in Houston in 1988 as Vice President, Business Development and was promoted to Senior Vice President, Business Management in 1992. Prior to joining EPCO, he was employed by Continental Emsco Supply Company, Ltd. and Amoco Canada Petroleum Company, Ltd. Gary L. Miller was elected as Executive Vice President, Chief Financial Officer, Treasurer and Director of the General Partner in April 1998. Mr. Miller has served as Executive Vice President, Chief Financial Officer and Treasurer of EPCO since 1990. He served as Senior Vice President, Controller and Treasurer of EPCO from 1988 to 1990. From 1983 to 1988 he served as Vice President, Treasurer and Controller of EPCO. Before joining EPCO, he was employed by Wanda Petroleum, where he was Assistant Controller from 1977 to 1980. William D. Ray was elected as Executive Vice President, Marketing and Supply of the General Partner in April 1998. Mr. Ray has served as EPCO's Executive Vice President, Marketing and Supply since 1985. Mr. Ray served as Vice President, Supply and Distribution of EPCO from 1971 to 1973 and as EPCO's Senior Vice President, Supply, Marketing and Distribution from 1973 to 1979. Prior to joining EPCO in 1971, Mr. Ray was employed by Wanda Petroleum from 1958 to 1969 and Koch as Vice President, Marketing and Supply from 1969 to 1971. Charles E. Crain was elected as Senior Vice President, Operations of the General Partner in April 1998 and has served as Senior Vice President, Operations of EPCO since 1991. Mr. Crain joined EPCO in 1980 as Vice President, Process Operations. Prior to joining EPCO, Mr. Crain held positions with Shell Oil Company, Air Products & Chemicals and Tenneco Chemicals. Michael R. Johnson was elected as General Counsel and Secretary of the General Partner in April 1998 and has served as General Counsel and Secretary of EPCO since 1982. Mr. Johnson joined EPCO as Senior Attorney in 1979. Before joining EPCO, Mr. Johnson was employed by the Internal Revenue Service for six years and spent two years in private practice in Tyler, Texas. Mr. Johnson also worked for the Department of Energy on the regional counsel staff of the Office of Special Counsel. Ralph S. Cunningham was elected as a Director of the General Partner in April 1998. Dr. Cunningham retired in 1997 from Citgo Petroleum Corporation, where he had served as President and Chief Executive Officer since 1995. Dr. Cunningham served as Vice Chairman of Huntsman Corporation from 1994 until 1995 and as President of Texaco Chemical Company from 1990 through 1994. Prior to joining Texaco Chemical Company, Dr. Cunningham held various executive positions with Clark Oil & Refining and Tenneco. He started his career in Exxon's refinery operations. He holds Ph.D., M.S. and B.S. degrees in Chemical Engineering. Dr. Cunningham serves as a director of Huntsman Corporation and Agrium, Inc. and served as a director of EPCO from 1987 to 1997. 38
Lee W. Marshall, Sr. was elected as a Director of the General Partner in April 1998. Mr. Marshall has been the Chief Executive Officer and principal stockholder of Bison International, Inc., and Bison Resources, LLC since 1991. Previously, Mr. Marshall was Executive Vice President and Chief Financial Officer of Wolverine Exploration Company and held senior management positions with Union Pacific Resources and Tenneco Oil. Item 11. Executive Compensation. The Company has no executive officers. The Company is managed by the General Partner, the executive officers of which are employees of, and the compensation of whom is paid by, EPCO. Pursuant to the EPCO Agreement, EPCO is reimbursed at cost for all expenses that it incurs managing the business and affairs of the Company, except that EPCO is not entitled to be reimbursed for any selling, general, and administrative expenses. In lieu of reimbursement for such selling, general, and administrative expenses, EPCO is entitled to receive an annual administrative services fee that currently equals $12.0 million. The Company paid EPCO $5.1 million in administrative services fees under the EPCO Agreement during 1998. The General Partner, with the approval and consent of the Audit and Conflicts Committee, has the right to agree to increases in such administrative services fee of up to 10% each year during the 10-year term of the EPCO agreement and may agree to further increases in such fee in connection with expansions of the Company's operations through the construction of new facilities or the completion of acquisitions that require additional management personnel. Compensation of Directors No additional remuneration is paid to employees of EPCO or the General Partner who also serve as directors of the General Partner. Each independent director receives $24,000 annually, for which each agrees to participate in four regular meetings of the Board of Directors and four Audit and Conflicts Committee meetings. Each independent director also receives $500 for each additional meeting in which he participates. In addition, each independent director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees thereof. Each director is fully indemnified by the Company for his actions associated with being a director to the extent permitted under Delaware law. 39
Item 12. Security Ownership of Certain Beneficial Owners and Management. The following table sets forth certain information as of March 1, 1999, regarding the beneficial ownership of (a) the Common Units and (b) the Subordinated Units of the Company by all directors of the General Partner, each of the named executive officers, all directors and executive officers as a group and all persons known by the General Partner to own beneficially more than 5% of the Common Units. <TABLE> <CAPTION> Percentage of Percentage of Percentage of Common Common Subordinated Subordinated Total Total Units (2) Units Units (2) Units Units Units Beneficially Beneficially Beneficially Beneficially Beneficially Beneficially Owned Owned Owned Owned Owned Owned ----- ----- ----- ----- ----- ----- <S> <C> <C> <C> <C> <C> <C> EPCO (1) 33,552,915 73.7% 21,409,870 100.0% 54,962,785 82.1% Dan Duncan (1) 33,552,915 73.7% 21,409,870 100.0% 54,962,785 82.1% O.S. Andras 100,000 0.2% - - 100,000 0.1% Randa L. Duncan - - - - - - Gary L. Miller - - - - - - Dr. Ralph S. Cunningham - - - - - - Lee W. Marshall - - - - - - All directors and executive officers as a group (10 persons) 33,655,915 75.3% 21,409,870 100.0% 55,065,785 83.2% </TABLE> ______________ (1) EPCO holds the Units through its wholly-owned subsidiary EPC Partners II, Inc. Mr. Duncan owns 57.1% of the voting stock of EPCO and, accordingly, exercises sole voting and dipositive power with respect to the Units held by EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of the members of Mr. Duncan's family, including Randa L. Duncan, a director and executive officer of the General Partner. The address of EPCO is 2727 North Loop West, Houston, Texas 77008. (2) For a discussion of the Company's Partners' Equity and the Units in general, see Note 6 of the Notes to Consolidated Financial Statements. Subordinated Units are non-voting. Section 16(a) Beneficial Ownership Reporting Compliance Under the federal securities laws, the General Partner, the General Partner's directors, executive (and certain other) officers, and any persons holding more than ten percent of the Common Units are required to report their ownership of Common Units and any changes in that ownership to the Company and the SEC. Specific due dates for these reports have been established by regulation and the Company is required to report in this proxy statement any failure to file by these dates in 1998. The Company believes that all of these filings were satisfied by the General Partner, the General Partner's directors and officers, and ten percent holders. As of March 1, 1999, the Company believes that the General Partner, and all of the General Partner's directors and officers and any ten percent holders are current in their filings. In making these statements, the Company has relied on the written representations of the General Partner, the General Partner's directors and officers, and ten percent holders and copies of reports that they have filed with the SEC. Item 13. Certain Relationships and Related Transactions. Ownership Interests of EPCO and its affiliates in the Company At December 31, 1998, EPC Partners II, Inc., a wholly owned subsidiary of EPCO, owned 33,552,915 Common Units and 21,409,870 Subordinated Units, representing a 49.1% interest and a 31.3% interest, respectively, in the Company. In addition, the General Partner owned a combined 2% interest in the Company and the Operating Partnership. In addition, another affiliate of EPCO, Enterprise Products 1998 Unit Option Plan Trust (the "1998 Trust") owned 660,890 Common Units as of December 31, 1998. The 1998 Trust was formed for the purpose of granting options in the 40
Company's securities to management and certain key employees. The 1998 Trust intends to purchase up to 339,110 additional Units on the open market or through privately negotiated transactions. Ownership Interests of other affiliates of the Company Another affiliate of the Company, EPOLP 1999 Grantor Trust (the "1999 Trust"), also intends to purchase up to 400,000 additional Common Units on the open market or through privately negotiated transactions. The 1999 Trust was formed to fund liabilities of a long-term incentive employee benefit plan. As of December 31, 1998, no Common Units had been purchased by the 1999 Trust. Related Party Transactions The Company, the Operating Partnership, the General Partner, EPCO and certain other parties have entered into various documents and agreements that generally govern the business of the Company and its affiliates. Such documents and agreements are not the result of arm's-length negotiations, and there can be no assurance that it, or that any of the transactions provided for therein, are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties. The Company has an extensive ongoing relationship with EPCO and its affiliates. These relationships include the following: (i) All management, administrative and operating functions for the Company are performed by officers and employees of EPCO pursuant to the terms of the EPCO Agreement. Under the EPCO Agreement, EPCO employs the operating personnel involved in the Company's business and is reimbursed at cost. (ii) EPCO is and will continue as operator of the plants and facilities owned by BEF, MBA, BRF, and EPIK and in connection therewith will charge such entities for actual salary costs and related fringe benefits. As operator of such facilities, EPCO also is entitled to be reimbursed for the cost of providing certain management services to such entities, which costs totaled $2.1 million in the aggregate for the year ended December 31, 1998. (iii) Although EPCO transferred a 49% economic interest in MBA to the Company, the Company is not a partner in such partnership. EPCO retains a 1% economic interest in such partnership and, except for the economic rights transferred by EPCO to the Company, continues to hold all rights as a partner under the partnership agreement for MBA, including the right to participate in the management and conduct of the business and affairs of such entity. (iv) EPCO and the Company have entered into an agreement pursuant to which EPCO provides trucking services to the Company. (v) EPCO retains the Retained Leases and, pursuant to the terms of the EPCO Agreement, subleases all of the facilities covered by the Retained Leases to the Company for $1 per year and has assigned its purchase options under the Retained Leases to the Company. EPCO is liable for the lease payments under the Retained Leases. (vi) Pursuant to the EPCO Agreement, the Company and the Operating Partnership participate as named insureds in EPCO's current insurance program, and costs attributable thereto are allocated among the parties on the basis of formulas set forth in such agreement. (vii) Pursuant to the EPCO Agreement, EPCO licenses certain trademarks and tradenames to the Company and indemnifies the Company for certain lawsuits and claims. 41
(viii) In the normal course of its business, the Company engages in transactions with BEF, MBA and other subsidiaries and divisions of EPCO. These transactions include the buying and selling of NGL products and the transportation of NGL products by truck. For a description of certain historical related party transactions between EPCO, the Company and their affiliates, see Note 8 of Notes to Consolidated Financial Statements. 42
PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Financial Statements" set forth on page F-1. (a)(3) Exhibits *3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. (Exhibit 3.1 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *3.2 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. (Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *3.3 LLC Agreement of Enterprise Products GP (Exhibit 3.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *4.1 Form of Common Unit certificate (Exhibit 4.1 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). 4.2 Credit Agreement among Enterprise Products Operating L.P., the Several Banks from Time to Time Parties Hereto, Den Norske Bank ASA, and Bank of Tokyo-Mitsubishi, Ltd., Houston Agency as Co- Arrangers, The Bank of Nova Scotia, as Co-Arranger and as Documentation Agent and The Chase Manhattan Bank as Co-Arranger and as Agent dated as of July 27, 1998 as Amended and Restated as of September 30, 1998. *10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products Texas Operating L.P. dated June 1, 1998 (Exhibit 10.1 to Registration Statement on Form S-1/A, File No: 333-52537, filed on July 8, 1998). *10.2 Form of EPCO Agreement between Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products Company (Exhibit 10.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.4 Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid Energy Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). 43
*10.5 Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333- 52537, filed on May 13, 1998). *10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995 (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.7 Articles of Partnership of Mont Belvieu Associates dated July 17, 1985 (Exhibit 10.7 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.8 First Amendment to Articles of Partnership of Mont Belvieu Associates dated July 15, 1996 (Exhibit 10.8 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.9 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978 (Exhibit 10.9 to Registration Statement on Form S-1, File No. 333-52537, dated May 13, 1998). *10.10 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.11 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities between Enterprise Products Company Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and Mont Belvieu Associates dated July 17, 1985 (Exhibit 10.11 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.12 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993 (Exhibit 10.12 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.13 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995 (Exhibit 10.13 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). 21.1 List of Subsidiaries of the Company 27.1 Financial Data Schedule _____________________ * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith 44
(b) Reports on Form 8-K The Company filed two Form 8-Ks during the quarter ending December 31, 1998. (I) Form 8-K dated October 19, 1998, reporting that the Company announced that its affiliate, EPCO intended to purchase up to 500,000 of the Company's Common Units in the open market or through privately negotiated transactions. A description of the intended transaction was filed according to Item 5, and the associated press release was filed pursuant to Item 7. (II) Form 8-K dated December 22, 1998, reporting that the Company announced that it, together with certain of its affiliates, may purchase up to 1,000,000 of the Company's Common Units in the open market or through privately negotiated transactions. At the time of the December 22, 1998 filing, the Company's affiliate, EPCO, had purchased, since October 19, 1998, 375,000 of the Company's Common Units in the open market and restated its intention to purchase up to 125,000 additional Common Units in the open market or through privately negotiated transactions. A description of the intended transaction was filed according to Item 5, and the associated press release was filed pursuant to Item 7. 45
INDEX TO FINANCIAL STATEMENTS Page Enterprise Products Partners L.P. Independent Auditors' Report............................................ F-2 Consolidated Balance Sheets as of December 31, 1997 and 1998............ F-3 Statements of Consolidated Operations for the Years Ended December 31, 1996, 1997 and 1998.................. F-4 Statements of Consolidated Cash Flows for the Years Ended December 31, 1996, 1997 and 1998.................. F-5 Statements of Consolidated Partners' Equity for the Years Ended December 31, 1996, 1997 and 1998.................. F-6 Notes to Consolidated Financial Statements.............................. F-7 Belvieu Environmental Fuels Independent Auditors' Report............................................ F-22 Balance Sheets as of December 31, 1997 and 1998......................... F-23 Statements of Operations for the Years Ended December 31, 1996, 1997 and 1998 ................. F-24 Statements of Cash Flows for the Years Ended December 31, 1996, 1997 and 1998.................. F-25 Statements of Partners' Equity for the Years Ended December 31, 1996, 1997 and 1998.................. F-26 Notes to Financial Statements........................................... F-27 All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto. F-1
Independent Auditors' Report Enterprise Products Partners L.P.: We have audited the accompanying consolidated balance sheets of Enterprise Products Partners L.P. (the "Company") as of December 31, 1997 and 1998, and the related statements of consolidated operations, consolidated cash flows and consolidated partners' equity for each of the years in the three-year period ended December 31, 1998. These consolidated financial statements are the responsibility of the management of the Company. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1997 and 1998, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1998 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Houston, Texas February 15, 1999 F-2
ENTERPRISE PRODUCTS PARTNERS L.P. CONSOLIDATED BALANCE SHEETS (AMOUNTS IN THOUSANDS) DECEMBER 31, ------------------------ 1997 1998 ASSETS ------------------------ CURRENT ASSETS Cash and cash equivalents, including restricted cash of $4,522 in 1997 $ 23,463 $ 24,103 Accounts receivable - trade 69,851 57,288 Accounts receivable - affiliates 6,682 15,546 Inventories 18,935 17,574 Current maturities of participation in notes receivable from unconsolidated affiliates 14,737 Prepaid and other current assets 8,103 8,445 ------------------------ Total current assets 127,034 137,693 PROPERTY, PLANT AND EQUIPMENT, NET 513,727 499,793 INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES 55,875 91,121 PARTICIPATION IN NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES 11,760 OTHER ASSETS 1,077 670 ------------------------ TOTAL $697,713 $741,037 ======================== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 14,903 Accounts payable - trade 76,591 $ 36,586 Accrued gas payables 45,668 27,183 Accrued expenses 8,638 7,540 Other current liabilities 21,544 11,462 ------------------------ Total current liabilities 167,344 82,771 LONG-TERM DEBT 215,334 90,000 MINORITY INTEREST 3,150 5,730 COMMITMENTS AND CONTINGENCIES PARTNERS' EQUITY Common Units (33,552,915 and 45,552,915 units outstanding at December 31, 1997 and 1998, respectively) 188,503 433,082 Subordinated Units (21,409,870 units outstanding at December 31, 1997 and 1998) 120,263 123,829 General Partner 3,119 5,625 ------------------------ Total partners' equity 311,885 562,536 ------------------------ TOTAL $697,713 $741,037 ======================== See Notes to Consolidated Financial Statements F-3
ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED OPERATIONS (Amounts in Thousands, Except per Unit Amounts) <TABLE> <CAPTION> Year Ended December 31, ------------------------------------------------------- 1996 1997 1998 ------------------------------------------------------- <S> <C> <C> <C> Revenues $999,506 $1,020,281 $738,902 ------------------------------------------------------- Cost and Expenses Operating costs and expenses 907,524 938,237 686,160 Selling, general and administrative 23,070 21,891 18,216 ------------------------------------------------------- Total 930,594 960,128 704,376 ------------------------------------------------------- Operating Income 68,912 60,153 34,526 ------------------------------------------------------- Other Income (Expense) Interest expense (26,310) (25,717) (14,696) Equity income in unconsolidated affiliates 15,756 15,682 15,671 Interest income from unconsolidated affiliates 809 Interest income - other 2,705 1,934 772 Other, net 364 638 273 ------------------------------------------------------- Other income (expense) (7,485) (7,463) 2,829 ------------------------------------------------------- Income before Extraordinary Item and Minority Interest 61,427 52,690 37,355 Extraordinary item--early extinguishment of debt (27,176) ------------------------------------------------------- Income before Minority Interest 61,427 52,690 10,179 Minority Interest (614) (527) (102) ------------------------------------------------------- Net Income $ 60,813 $ 52,163 $ 10,077 ======================================================= Allocation of Net Income to: Limited partners $ 60,205 $ 51,641 $ 9,976 ======================================================= General partner $ 608 $ 522 $ 101 ======================================================= Income per Unit Before Extraordinary Item $1.10 $.94 $.62 Extraordinary item (.45) ------------------------------------------------------- Net Income per Unit $1.10 $.94 $.17 ======================================================= Weighted-average number of units outstanding 54,963 54,963 60,124 ======================================================= </TABLE> See Notes to Consolidated Financial Statements F-4
ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED CASH FLOWS (AMOUNTS IN THOUSANDS) <TABLE> <CAPTION> Year Ended December 31, ----------------------------------------------- 1996 1997 1998 ----------------------------------------------- <S> <C> <C> <C> Operating Activities Net income $ 60,813 $ 52,163 $ 10,077 Adjustments to reconcile net income to cash flows provided by (used for) operating activities: Extraordinary item - early extinguishment of debt 27,176 Depreciation and amortization 15,742 17,684 19,194 Equity in income of unconsolidated affiliates (15,756) (15,682) (15,671) Leases paid by EPCO 4,010 Minority interest 614 527 102 (Gain) loss on sale of assets 155 (276) Net effect of changes in operating accounts 30,018 2,948 (64,906) ----------------------------------------------- Operating activities cash flows 91,431 57,795 (20,294) ----------------------------------------------- Investing Activities Capital expenditures (61,010) (33,636) (8,360) Proceeds from sale of assets 25 1,887 Participation in notes receivable from unconsolidated affiliates: Purchase of notes receivable (33,725) Collection of notes receivable 7,228 Unconsolidated affiliates: Investments in and advances to (3,894) (4,625) (26,842) Distributions received 7,154 7,279 9,117 ----------------------------------------------- Investing activities cash flows (57,725) (30,982) (50,695) ----------------------------------------------- Financing Activities Net proceeds from sale of common units 243,296 Long-term debt borrowings 24,001 598 90,000 Long-term debt repayments (50,040) (25,978) (257,413) Net increase (decrease) in restricted cash 1,109 (1,171) 4,522 Cash contributions from EPCO to minority interest 2,478 Cash dividends paid (21,645) ----------------------------------------------- Financing activities cash flows (24,930) (26,551) 61,238 ----------------------------------------------- Cash Contributions from (to) epco 6,393 (6,299) 14,913 ----------------------------------------------- Net Change in Cash and Cash Equivalents 15,169 (6,037) 5,162 Cash and Cash Equivalents, January 1 9,809 24,978 18,941 ----------------------------------------------- Cash and Cash Equivalents, December 31 (Excluding restricted cash of $3,351 in 1996 and $4,522 in 1997) $ 24,978 $ 18,941 $ 24,103 =============================================== </TABLE> See Notes to Consolidated Financial Statements F-5
ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY (Amounts in Thousands) <TABLE> <CAPTION> Limited Partners ----------------------------- Common Subordinated General Units Units Partner Total -------------------------------------------------------------- <S> <C> <C> <C> <C> Consolidated Partners' Equity, January 1, 1996 $120,164 $ 76,663 $1,988 $198,815 Net Income 36,755 23,450 608 60,813 Cash contributions from EPCO 3,864 2,465 64 6,393 -------------------------------------------------------------- Consolidated Partners' Equity, December 31, 1996 160,783 102,578 2,660 266,021 Net Income 31,527 20,114 522 52,163 Cash distributions to EPCO (3,807) (2,429) (63) (6,299) -------------------------------------------------------------- Consolidated Partners' Equity, December 31, 1997 188,503 120,263 3,119 311,885 Net Income 5,641 4,335 101 10,077 Cash contributions from EPCO 7,519 4,813 2,581 14,913 Leases paid by EPCO after public offering 2,701 1,269 40 4,010 Proceeds from sale of Common Units 243,296 243,296 Cash distributions to Unitholders ($.32 per unit on Common and Subordinated Units) (14,578) (6,851) (216) (21,645) -------------------------------------------------------------- Consolidated Partners' Equity, December 31, 1998 $433,082 $123,829 $5,625 $562,536 ============================================================== </TABLE> See Notes to Consolidated Financial Statements F-6
ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ENTERPRISE PRODUCTS PARTNERS L.P. (the "Company") was formed on April 9, 1998 as a Delaware limited partnership to own and operate the natural gas liquids ("NGL") business of Enterprise Products Company ("EPCO"). The Company is the limited partner and owns 99% of Enterprise Products Operating L.P. (the "Operating Partnership"), which directly or indirectly owns or leases and operates the NGL facilities. Enterprise Products GP, LLC (the "General Partner") is the general partner and owns 1.0101% of the Operating Partnership and 1% of the Company. Both the Company and the General Partner are subsidiaries of EPCO. Prior to their consolidation, EPCO and its affiliated companies were controlled by members of a single family, who collectively owned at least 90% of each of the entities for all periods presented. As of April 30, 1998, the owners of all the affiliated companies exchanged their ownership interests for shares of EPCO. Accordingly, each of the affiliated companies became a wholly owned subsidiary of EPCO or was merged into EPCO as of April 30, 1998. In accordance with generally accepted accounting principles, the consolidation of the affiliated companies with EPCO was accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. Under terms of a contract entered into on May 8, 1998 between EPCO and the Operating Partnership, EPCO contributed all of its NGL assets through the Company and the General Partner to the Operating Partnership and the Operating Partnership assumed certain of EPCO's debt. As a result, the Company became the successor to the NGL operations of EPCO. Effective July 27, 1998, the Company filed a registration statement pursuant to an initial public offering of 12,000,000 Common Units. The Common Units sold for $22 per unit. The Company received approximately $243.3 million after underwriting commissions of $16.8 million and expenses of approximately $3.9 million. The accompanying consolidated financial statements include the historical accounts and operations of the NGL business of EPCO, including NGL operations conducted by affiliated companies of EPCO prior to their consolidation with EPCO. Investments in which the Company owns 20% to 50% and exercises significant influence over operating and financial policies are accounted for using the equity method. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior years' financial statements to conform to the presentation of the current period financial statements. INVENTORIES, consisting of NGLs and NGL products, are carried at the lower of average cost or market. EXCHANGES are movements of NGL products between parties to satisfy timing and logistical needs of the parties. NGLs and NGL products borrowed from the Company under such agreements are included in inventories, and NGLs and NGL products loaned to the Company under such agreements are accrued as a liability in accrued gas payables. PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using the straight-line method over the asset's estimated useful life. Maintenance, repairs and minor renewals are charged to operations as incurred. Additions, improvements and major renewals are capitalized. The cost of assets retired or sold, together with the related accumulated F-7
depreciation, is removed from the accounts, and any gain or loss on disposition is included in income. REVENUE is recognized when products are shipped or services are rendered. USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period are required for the preparation of financial statements in conformity with generally accepted accounting principles. Actual results could differ from these estimates. FEDERAL INCOME TAXES are not provided because the Company and its predecessors either had elected under provisions of the Internal Revenue Code to be a Master Limited Partnership or Subchapter S Corporation or were organized as pass-through entities for federal income tax purposes. As a result, for federal income taxes purposes, the owners are individually responsible for the taxes on their allocable share of the consolidated taxable income of the Company. State income taxes are not material. ENVIRONMENTAL COSTS for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate costs to remediate the site. Ongoing environmental compliance costs are charged to expense as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental costs, accrued environmental liabilities and expenditures to mitigate or eliminate future environmental contamination for each of the years in the three-year period ended December 31, 1998 were not significant to the consolidated financial statements. The Company's estimated liability for environmental remediation is not discounted. CASH FLOWS are computed using the indirect method. For cash flow purposes, the Company considers all highly liquid debt instruments with an original maturity of less than three months at the date of purchase to be cash equivalents. All cash presented as restricted cash in the Company's financial statements was due to requirements of the Company's debt agreements. DOLLAR AMOUNTS presented in the tabulations within the notes to the Company's financial statements are stated in thousands of dollars, unless otherwise indicated. RECENT STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS ("SFAS") include the following: (effective for all fiscal quarters of fiscal years beginning after June 15, 1999) SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Management is currently studying this SFAS item for its possible impact on the consolidated financial statements. On April 3, 1998, the American Institute of Certified Public Accountants issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up Activities." For years beginning after December 15, 1998, SOP 98-5 requires that all start-up costs of a business activity be charged to expense as incurred and any start-up cost previously deferred should be written off as a cumulative effect of a change in accounting principle. Based on the assessment of SOP 98-5, SOP 98-5 will not have a material impact on the consolidated financial statements except for a $4.5 million noncash write- off at January 1, 1999 of the unamortized balance of deferred start-up costs of Belvieu Environmental Fuels, in which the Company owns a 33-1/3% economic interest. Such a write-off would cause a $1.5 million reduction in the equity in income of unconsolidated affiliates for 1999 and a corresponding reduction in the Company's investment in unconsolidated affiliates. INCOME PER UNIT is based on the amount of income allocated to limited partners and the weighted-average number of Common Units and Subordinated Units outstanding during the F-8
period. The Company has no dilutive securities outstanding; accordingly, no diluted net income per Unit is presented. 2. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment and accumulated depreciation are as follows: <TABLE> <CAPTION> Estimated Useful Life in Years 1997 1998 -------------------------------------------------- <S> <C> <C> <C> Plants and pipelines............................. 5-35 $599,047 $611,994 Underground and other storage facilities......... 5-35 79,744 89,064 Transportation equipment......................... 3-35 12,393 3,043 Land............................................. 12,783 12,362 Construction in progress......................... 12,627 3,879 --------------------------- Total................................. 716,594 720,342 Less accumulated depreciation.................... 202,867 220,549 --------------------------- Property, plant and equipment, net............... $513,727 $499,793 =========================== </TABLE> 3. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES At December 31, 1998, the Company's significant unconsolidated affiliates which were accounted for using the equity method included the following: Belvieu Environmental Fuels ("BEF") - a 33-1/3% economic interest in a Methyl Tertiary Butyl Ether ("MTBE") production facility. Mont Belvieu Associates ("MBA") - a 49% economic interest in an entity which owns a 50% interest in a NGL fractionation facility. Baton Rouge Fractionators, LLC ("BRF") - a 27.5% economic interest in a NGL fractionation facility which is under construction and scheduled to begin production during the second quarter of 1999. EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate economic interest in a refrigerated NGL marine terminal loading facility which is under construction. Other joint ventures included various entities in the formation stage at December 31, 1998. F-9
Following is a summary of the Company's investments in and advances to unconsolidated affiliates and the equity in income of unconsolidated affiliates: Investments in and advances to unconsolidated affiliates at: <TABLE> <CAPTION> December 31, 1997 December 31, 1998 ------------------------------------------ <S> <C> <C> BEF.................................................. $41,278 $50,079 MBA.................................................. 11,963 12,551 BRF.................................................. 2,634 17,896 EPIK................................................. 5,667 Other................................................ 4,928 ------------------------------------------ Total.......................................... $55,875 $91,121 ========================================== </TABLE> Equity in income of unconsolidated affiliates for the: <TABLE> <CAPTION> Years Ended December 31, --------------------------------------------------- 1996 1997 1998 --------------------------------------------------- <S> <C> <C> <C> BEF........................... $ 9,752 $ 9,305 $ 9,801 MBA........................... 6,004 6,377 5,213 BRF........................... (91) EPIK.......................... 748 --------------------------------------------------- Total................... $15,756 $15,682 $15,671 =================================================== </TABLE> At December 31, 1998, the Company's share of accumulated earnings of unconsolidated affiliates that had not been remitted to the Company was $33 million. F-10
Following is selected financial data for the most significant investments of the Company: BEF BEF is owned equally (33-1/3%) by Mitchell Gas Services, L.P. ("Mitchell"), SUN BEF, Inc. ("SUN BEF") and the Company. Mitchell Energy & Development Corp. is Mitchell's ultimate parent company, and Sun Company, Inc. ("Sun") is SUN BEF's ultimate parent company. Following is condensed financial data for BEF: <TABLE> <CAPTION> At December 31, ---------------------------------------- BALANCE SHEET DATA: 1997 1998 ---------------------------------------- <S> <C> <C> Current assets.............................................. $ 40,189 $ 34,268 Property, plant and equipment, net.......................... 182,945 172,281 Other assets................................................ 18,323 13,684 ---------------------------------------- Total assets............................................. $241,457 $220,233 ======================================== Current liabilities......................................... $ 57,344 $ 54,326 Long-term debt.............................................. 58,667 19,556 Other liabilities........................................... 2,950 1,798 Partners' equity............................................ 122,496 144,553 ---------------------------------------- Total liabilities and partners' equity................... $241,457 $220,233 ======================================== </TABLE> <TABLE> <CAPTION> Years Ended December 31, ---------------------------------------------------------- 1996 1997 1998 ---------------------------------------------------------- <S> <C> <C> <C> INCOME STATEMENT DATA: Revenues...................................... $217,438 $233,218 $182,001 Expenses...................................... 188,182 205,300 152,600 ---------------------------------------------------------- Net income................................ $ 29,256 $ 27,918 $ 29,401 ========================================================== </TABLE> BEF's owners are required under isobutane supply contracts to provide their pro rata share of BEF's monthly isobutane requirements. If the MTBE plant's isobutane requirements exceed 450,000 barrels for any given month, each of the owners retains the right, but not the obligation, to supply at least one-third of the additional isobutane needed. The purchase price for the isobutane (which generally approximates the established market price) is based on contracts between the owners. BEF has a ten-year off-take agreement through May 2005 under which Sun is required to purchase all of the plant's MTBE production. Through May 31, 2000, Sun pays the higher of a contractual floor price or market price (as defined within the agreement) for floor production (193,450,000 gallons per year) and the market price for production in excess of 193,450,000 gallons per year, subject to quarterly adjustments on certain excess volumes. At floor production levels, the contractual floor price is a price sufficient to cover essentially all of BEF's operating costs plus principal and interest payments on its bank term loan. Market price is (a) toll fee price (cost of feedstock plus approximately $0.484 per gallon during the first two contract years ended May 31, 1997) and (b) at Sun's option, the toll fee price (cost of feedstock plus approximately $0.534 per gallon) or the U.S. Gulf Coast Posted Contract Price for the period from June 1, 1997 through May 31, 2000. For purposes of computing the toll fee price, the feedstock component is based on the Normal Butane Posted Price for the month plus the average purchase price paid by BEF to acquire methanol consumed by the facility during the month. In addition, the floor or market price determined above will be increased by $0.03 per gallon in the third and fourth contract years and by about $0.04 per gallon in the fifth contract year. Beginning June 1, 2000, through the remainder of the agreement, the price for all production will be based on a market-related negotiated price. F-11
The contracted floor price paid by Sun for production in 1996, 1997 and 1998 exceeded the spot market price for MTBE. At December 31, 1998, the floor price paid for MTBE by Sun was $.78 per gallon. The average Gulf Coast MTBE spot market price was $.46 per gallon for December 1998 and $.64 per gallon for all of 1998. Substantially all revenues earned by BEF are from the production of MTBE which is sold to Sun. This concentration could impact BEF's exposure to credit risk; however, such risk is reduced since Sun has an equity interest in BEF. Management believes BEF is exposed to minimal credit risk. BEF does not require collateral for its receivables from Sun. Long-term debt of BEF consists of a five-year, floating interest rate (London Interbank Offered Rate ["LIBOR"] plus .0875%) bank term note payable ($58.7 million outstanding at December 31, 1998) which is due in equal quarterly installments of $9.8 million through May 31, 2000. The weighted-average interest rate on this debt for the year ended December 31, 1998 was 6.60%. The debt is non-recourse debt to the partners. BEF had an interest rate cap agreement (based on a LIBOR rate of 7%) with a notional amount of $13 million at December 31, 1998. The interest rate cap agreement provides that the notional amount will decrease by $4.5 million each quarter through May 1999. BEF intends to hold the contract through its expiration date and use it as a means of fixing a portion of the interest on the term note payable. While the notional amount is used to express the magnitude of an interest rate cap agreement, the amount subject to credit risk, in the event of nonperformance by a third party, is substantially less. Management does not expect any significant impact to its financial position as a result of nonperformance by a third party. The interest rate cap did not have a significant effect on the net interest rate that BEF recognized for 1996, 1997 or 1998. The bank term loan agreement contains restrictive covenants prohibiting or limiting certain actions of BEF, including partner distributions, and requiring certain actions by BEF, including the maintenance of specified levels of leverage, as defined, and approval by the banks of certain contracts. Distributions to partners in the amount of $7.3 million were made for the year ended December 31, 1998. In addition, the loan agreement requires BEF to restrict a certain portion of cash to pay for the plant's turnaround maintenance and long-term debt service. At December 31, 1997 and 1998, cash of $13.1 million and $11.1 million, respectively, was restricted under terms of the loan agreement. BEF was in compliance with the restrictive covenants at December 31, 1998. The long-term debt is collateralized by substantially all of BEF's assets. F-12
MBA Kinder Morgan Natural Gas Liquids Corporation owns 50%, the Company owns 49% and EPCO owns 1% of Mont Belvieu Associates. Following is the condensed financial data for MBA: <TABLE> <CAPTION> At December 31, ---------------------------------------- BALANCE SHEET DATA: 1997 1998 ---------------------------------------- <S> <C> <C> Current assets............................................... $ 6,125 $ 4,756 Property, plant and equipment, net........................... 45,774 44,205 Other assets................................................. 79 1,687 ---------------------------------------- Total assets.............................................. $51,978 $50,648 ======================================== Current liabilities.......................................... $ 4,479 $ 1,582 Long-term debt............................................... 11,790 11,790 Other liabilities............................................ 130 Partners' equity............................................. 35,709 37,146 ---------------------------------------- Total liabilities and partners' equity.................... $51,978 $50,648 ======================================== </TABLE> <TABLE> <CAPTION> Years Ended December 31, ------------------------------------------------------------ 1996 1997 1998 ------------------------------------------------------------ <S> <C> <C> <C> INCOME STATEMENT DATA: Revenues................................... $26,954 $33,646 $31,881 Expenses................................... 16,347 23,034 22,280 ------------------------------------------------------------ Net income............................... $10,607 $10,612 $ 9,601 ============================================================ </TABLE> Long-term debt of MBA represents an $11.6 million bank term note which is payable over a six-year amortization schedule and a balloon payment in December 2001 of $3 million. Interest on the bank term note payable bears interest at LIBOR plus 0.75%. The weighted-average interest rate was 5.79% at December 31, 1998. The loan is nonrecourse to the partners and is secured by MBA's rights under the operating agreement of the facility with the joint owners. The bank agreement contains no restrictions on the payment of distributions to the partners. Also included in long-term debt is a $0.2 million note payable to EPCO. All of MBA's revenues are derived from NGL fractionation services to customers in the Gulf Coast area. This concentration could impact MBA's exposure to credit risk since these customers could be affected by similar economic or other conditions. Management, however, believes MBA is exposed to minimal credit risk. MBA generally does not require collateral for its receivables. BRF BRF is a joint venture among Amoco Louisiana Fractionator Company, Williams Mid- Stream Natural Gas Liquids, Inc., Exxon Chemical Louisiana LLC ("Exxon") and the Company. At December 31, 1998, the joint venture agreement was not finalized. The ownership interests in BRF will be based on the amounts contributed by each member to fund certain capital expenditures. Exxon will fund a small portion of the construction costs but will contribute other NGL assets. At December 31, 1998, included in investments in and advances to unconsolidated affiliates, the Company recorded 27.5% of the $0.3 million operating loss as a result of certain start-up expenses incurred during the developmental stage. F-13
BRF is an NGL fractionation facility under construction near Baton Rouge, Louisiana, which will have a 60,000 barrel per day capacity. The Company is the operator of the facility, which will service NGL production from the Mobile/Pascagoula and Louisiana areas. Following is the condensed balance sheet data for BRF: <TABLE> <CAPTION> At December 31, ----------------------------------------- 1997 1998 ----------------------------------------- <S> <C> <C> Current assets.............................................. $2,511 $ 2,386 Construction in progress.................................... 4,634 58,618 Other....................................................... 3 ----------------------------------------- Total assets............................................. $7,145 $61,007 ========================================= Current liabilities......................................... $3,379 $ 8,222 Members' equity............................................. 3,766 52,785 ----------------------------------------- Total liabilities and members' equity.................... $7,145 $61,007 ========================================= </TABLE> EPIK EPIK is a joint venture among EPIK Gas Liquids LLC ("Gas Liquids"), the 1% general partner, the Operating Partnership and Idemitsu LPG USA Corporation ("Idemitsu"). The Operating Partnership and Idemitsu each are 49.5% limited partners. EPIK was formed to construct and own refrigerated NGL marine terminal loading facilities. The Operating Partnership operates the facilities for EPIK and acts as the contractor for construction of the assets. Construction of certain assets was completed during 1998, and EPIK began their operations in June 1998. EPIK expects the remaining construction to be completed during the fourth quarter of 1999. Following is the condensed financial data for EPIK as of and for the year ended December 31, 1998: <TABLE> <CAPTION> BALANCE SHEET DATA: <S> <C> Current assets............................................... $ 1,332 Property, plant and equipment, net........................... 11,939 -------------------- Total assets.............................................. $13,271 ==================== Current liabilities.......................................... $ 36 Partners' equity............................................. 13,235 -------------------- Total liabilities and partners' equity.................... $13,271 ==================== </TABLE> <TABLE> <CAPTION> INCOME STATEMENT DATA: <S> <C> Revenues..................................................... $3,962 Expenses..................................................... 2,200 -------------------- Net income.............................................. $1,762 ==================== </TABLE> F-14
4. NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES On July 31, 1998, the Company purchased a participation interest in bank loans of MBA and BEF for $33.7 million. Participation interest in the MBA bank note receivable totaled approximately $7.7 million at the time of the purchase. The MBA note receivable bears interest at a floating rate per annum at LIBOR plus 0.75% and matures on December 31, 2001. The Company will receive monthly principal payments, aggregating approximately $1.7 million per year, plus interest from MBA during the term of the loan with an additional $1.8 million lump sump payment upon maturity in December 2001. Participation interest in the BEF bank note receivable totaled $26.1 million at the time of purchase. The BEF note receivable bears interest at a floating rate per annum at LIBOR plus 0.0875% and matures on May 31, 2000. The Company will receive quarterly principal payments of approximately $3.3 million plus interest from BEF during the term of the loan. 5. LONG-TERM DEBT On July 31, 1998, the Company entered into a $200 million revolving credit agreement (the "Bank Revolver") with a bank syndicate. The Bank Revolver is due on July 31, 2000 and bears interest at various rates based on the bank's prime rate, three-month certificate of deposit rate, as defined, federal funds effective rate or Eurodollar rate. The Company elects the basis for the interest rate at the time of each borrowing. Interest rates ranged from 6.25% to 6.69% during 1998, and the weighted-average interest rate at December 31, 1998 was 6.45%. Long-term debt consisted of the following: <TABLE> <CAPTION> At December 31, ----------------------------------------- 1997 1998 ----------------------------------------- <S> <C> <C> Bank Revolver.............................................. $90,000 Insurance Companies: Secured notes (five separate series), with interest from 8.82% to 12.10% at December 31, 1997, retired during 1998.................................................... $ 65,395 Senior notes (seven separate series), with interest from 8.04% to 12.10% at December 31, 1997, retired during 1998.................................................... 160,345 Subordinated note, with interest at 9.3% at December 31, 1997, retired during 1998............................... 4,497 ----------------------------------------- Total........................................... 230,237 90,000 Less current maturities of long-term debt.................. 14,903 ----------------------------------------- Long-term debt............................................. $215,334 $90,000 ========================================= </TABLE> The Bank Revolver contains restrictive covenants prohibiting or limiting certain actions of the Company, including payment of cash distributions to owners, making of certain investments and incurring any additional debt. Additionally, the Bank Revolver requires certain actions by the Company including the maintenance of specified levels of working capital and tangible net worth, as defined by the agreement. The Company was in compliance with these restrictive covenants at December 31, 1998. At December 31, 1998, the Company had $30 million of standby letters of credit available, and approximately $0.7 million of letters of credit were outstanding under letter of credit agreements with the banks. F-15
Extraordinary Item--Early Extinguishment of Debt On July 31, 1998, the Company used $243.3 million of proceeds from the sale of Common Units and $13.3 million of borrowings from the Bank Revolver to retire $256.6 million of debt that was assumed from EPCO. In connection with the repayment of the debt, the Company was required to pay a "make-whole payment" of $26.3 million to the lenders. The $26.3 million (plus $0.9 million of unamortized debt costs) is included in the consolidated statement of operations for the year ended December 31, 1998 as "Extraordinary item--early extinguishment of debt." 6. PARTNERS' CAPITAL AND CASH DISTRIBUTIONS At December 31, 1998, the Company had 45.6 million Common Units and 21.4 million Subordinated Units outstanding (collectively, "Units"). The Subordinated Units have no voting rights until the Units are converted into Common Units at the end of the Subordination Period (as defined below). The Agreement of Limited Partnership of the Company (the "Partnership Agreement") contains specific provisions for the allocation of net earnings and losses to the Common Units, Subordinated Units and the General Partner. The Partnership Agreement also sets forth the calculation to be used to determine the amount and priority of cash distributions that the Common Unitholders, Subordinated Unitholders and the General Partner will receive. The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of $0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set forth in the Partnership Agreement. With respect to each quarter during the subordination period, which will generally not end before June 30, 2003, the Common Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages thereon, and the General Partner will have the right to receive the related distribution on its interest before any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. During the year ended December 31, 1998, the Company declared cash distributions of $.32 per Unit as of October 30, 1998 on all partnership interests. The Subordination Period for the Subordinated Units will generally extend until the first day of any quarter beginning after June 30, 2003 when the Conversion Test has been satisfied. Generally, the Conversion Test will have been satisfied when the Company has paid from Operating Surplus and generated from Adjusted Operating Surplus the minimum quarterly distribution on all Units for the three preceding four-quarter periods. Upon expiration of the Subordination Period, all remaining Subordinated Units will convert into Common Units on a one-for-one basis and will thereafter participate pro rata with the other Common Units in distributions of Available Cash. If the Conversion Test has been met for any quarter ending on or after June 30, 2001, 25% of the Subordinated Units will convert into Common Units. If the Conversion Test has been met for any quarter ending on or after June 30, 2002, an additional 25% of the Subordinated Units will convert into Common Units. The early conversion of the second 25% of Subordinated Units may not occur until at least one year following the early conversion of the first 25% of Subordinated Units. The Partnership Agreement generally authorizes the Company to issue an unlimited number of additional limited partner interests and other equity securities of the Company for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion without the approval of the Unitholders. During the Subordination Period, however, the Company may not issue equity securities ranking senior to the Common Units for an aggregate of more than 22,775,000 Common Units (except for Common Units upon conversion of Subordinated Units, pursuant to employee benefit plans, upon conversion of the general partner interest as a result of the withdrawal of the General Partner or in connection with acquisitions or F-16
capital improvements that are accretive on a per Unit basis) or an equivalent number of securities ranking on a parity with the Common Units, without the approval of the holders of at least a Unit Majority. A Unit Majority is defined as at least a majority of the outstanding Common Units (during the Subordination Period), excluding Common Units held by the General Partner and its affiliates, and at least a majority of the outstanding Common Units (after the Subordination Period). 7. MAJOR CUSTOMERS A customer owns a 45.4% undivided interest in a plant and the related pipeline system and it leases such undivided interest in these facilities to the Company. The agreement with the customer expires in 2004. There are two successive options to extend the term for 12 years each remaining under the original agreement. Revenues from sales to this customer were approximately $114.1 million, $147.6 million and $102.2 million for 1996, 1997 and 1998, respectively. In addition, the Company has supply, transportation and storage contracts with another customer which expire in 2003. Under the supply contract, the Company sells approximately 390,000 barrels of isobutane per month to the customer. Under the transportation contract, the Company delivers the product sold at a transportation fee of approximately 0.75 cents per gallon. Storage fees are charged at a rate of 7.5 cents per gallon for any product held for the customer and then subsequently sold to third parties. Revenues from sales to this customer were approximately $113.4 million, $107.3 million and $64.4 million for 1996, 1997 and 1998, respectively. 8. RELATED PARTY TRANSACTIONS The Company has no employees. All management, administrative and operating functions are performed by employees of EPCO. Operating costs and expenses include charges for EPCO's employees who operate the Company's various facilities. Such charges are based on EPCO's actual salary costs and related fringe benefits. Because the Company's operations constitute the most significant portion of EPCO's consolidated operations, selling, general and administrative expenses reported in the accompanying statements of consolidated operations for all periods before the public offering include all such expenses incurred by EPCO less amounts directly incurred by other subsidiaries or operating divisions of EPCO. In connection with the initial public offering, EPCO, the General Partner and the Company entered into the EPCO Agreement pursuant to which (i) EPCO agreed to manage the business and affairs of the Company and the Operating Partnership; (ii) EPCO agreed to employ the operating personnel involved in the Company's business for which EPCO is reimbursed by the Company at cost; (iii) the Company and the Operating Partnership agreed to participate as named insureds in EPCO's current insurance program, and costs are allocated among the parties on the basis of formulas set forth in the agreement; (iv) EPCO agreed to grant an irrevocable, nonexclusive worldwide license to all of the trademarks and trade names used in its business to the Company; (v) EPCO agreed to indemnify the Company against any losses resulting from certain lawsuits; and (vi) EPCO agreed to sublease all of the equipment which it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 rail cars to the Company for $1 per year and assigned its purchase options under such leases to the Company (hereafter referred to as "Retained Leases".) Pursuant to the EPCO Agreement, EPCO is reimbursed at cost for all expenses that it incurs in connection with managing the business and affairs of the Company, except that EPCO is not entitled to be reimbursed for any selling, general and administrative expenses. In lieu of reimbursement for such selling, general and administrative expenses, EPCO receives an annual administrative services fee that initially equals $12.0 million. The General Partner, with the approval and consent of the Audit and Conflicts Committee of the Company, can agree to increases in such administrative services fee of up to 10% each year during the ten-year term of the EPCO Agreement and may agree to further increases in such fee in F-17
connection with expansions of the Company's operations through the construction of new facilities or the completion of acquisitions that require additional management personnel. EPCO also operates all plants owned by the unconsolidated affiliates and charges them for actual salary costs and related fringe benefits. In addition, EPCO charged the unconsolidated affiliates for management services provided; such charges aggregated $1.1 million for 1996, $1.1 million for 1997 and $2.1 million for 1998. Since EPCO pays the rental charges for the Retained Leases, such payments are considered a contribution by EPCO for the benefit of each partnership interest and are included as such in Partners' Equity, and a corresponding charge for the rental expense is included in the consolidated statements of operations. Rental expense, included in operating costs and expenses, for the Retained Leases was $11.4 million, $13.3 million and $13.9 million (of which $4.0 million occurred after the public offering) for 1996, 1997 and 1998, respectively. The Company also has transactions in the normal course of business with the unconsolidated affiliates and other subsidiaries and divisions of EPCO. Such transactions include the buying and selling of NGL products, loading of NGL products and transportation of NGL products by truck. Following is a summary of significant transactions with related parties: <TABLE> <CAPTION> For the Years Ended December 31 ---------------------------------------------- 1996 1997 1998 ---------------------------------------------- <S> <C> <C> <C> Revenues from NGL products sold to: Unconsolidated affiliates............................ $41,653 $44,392 $36,474 Other EPCO subsidiaries.............................. 10,292 19,029 19,531 Cost of NGL products purchased from: Unconsolidated affiliates............................ 7,339 8,453 9,270 Other EPCO subsidiaries.............................. 3,944 6,495 5,293 Operating expenses charged for trucking of NGL products..................................... 9,114 7,606 4,704 Administrative service fee charged by EPCO............. 5,129 </TABLE> 9. COMMITMENTS AND CONTINGENCIES Storage Commitments The Company stores NGL products for EPCO and various third parties. Under the terms of the storage agreements, the Company is generally required to redeliver to the owner its NGL products upon demand. The Company is insured for any physical loss of such NGL products due to catastrophic events. At December 31, 1998, NGL products aggregating 337 million gallons were due to be redelivered to the owners under various storage agreements. Lease Commitments The Company leases certain processing facilities under noncancelable leases. Minimum future rental payments on such leases with terms in excess of one year at December 31, 1998 are as follows: <TABLE> <S> <C> 1999................................................................... $ 4,468 2000................................................................... 4,456 2001................................................................... 4,455 2002................................................................... 4,251 2003................................................................... 4,252 Thereafter............................................................. 4,251 ----------- Total minimum obligations................................... $26,133 =========== </TABLE> F-18
Lease expense charged to operations (including Retained Leases) for the years ended December 1996, 1997 and 1998 was approximately $26.3 million, $29.6 million and $18.5 million, respectively. Capital Expenditure Commitments As of December 31, 1998, the Company had capital expenditure commitments totaling approximately $11.1 million, the majority of which relates to the construction of projects of unconsolidated affiliates. Litigation EPCO has indemnified the Company against any litigation arising from events or actions prior to its formation. The Company is sometimes named as a defendant in litigation relating to its normal business operations. Although the Company insures itself against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify the Company against liabilities arising from future legal proceedings as a result of its ordinary business activity. Management is aware of no significant litigation, pending or threatened, that would have a significantly adverse effect on the Company's financial position or results of operations. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The following disclosure of estimated fair value was determined by the Company, using available market information and appropriate valuation methodologies. Considerable judgment, however, is necessary to interpret market data and develop the related estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize upon disposition of the financial instruments. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and Cash Equivalents, Accounts Receivable, Participation in Notes Receivable from Unconsolidated Affiliates, Accounts Payable, Accrued Expenses and Long-Term Debt are carried at amounts which reasonably approximate their fair value at year end. F-19
11. SUPPLEMENTAL CASH FLOWS DISCLOSURE The net effect of changes in operating assets and liabilities is as follows: <TABLE> <CAPTION> Year Ended December 31, -------------------------------------------------------- 1996 1997 1998 -------------------------------------------------------- <S> <C> <C> <C> (Increase) decrease in: Accounts receivable......................... $(34,763) $ 29,024 $ 3,699 Inventories................................. 5,947 7,329 1,361 Prepaids and other current assets........... 100 917 (342) Other assets................................ 295 127 46 Increase (decrease) in: Accounts payable--trade..................... 35,187 (3,320) (40,005) Accrued gas payable......................... 21,650 (26,955) (18,485) Accrued expenses............................ 6,286 (5,526) (1,098) Other current liabilities................... (4,684) 1,352 (10,082) -------------------------------------------------------- Net effect of changes in operating accounts.... $ 30,018 $ 2,948 $(64,906) ======================================================== Cash payments for interest, net of $1,569, $2,005 and $180 capitalized in 1996, 1997 and 1998, respectively...................... $ 30,156 $ 28,352 $ 6,971 ======================================================== </TABLE> During 1998, the Company contributed $1.9 million (at net book value) of plant equipment to an unconsolidated affiliate as part of its investment therein. 12. CONCENTRATION OF CREDIT RISK A substantial portion of the Company's revenues is derived from the fractionation, isomerization, propylene production, marketing, storage and transportation of NGLs to various companies in the NGL industry, primarily located in the United States. Although this concentration could affect the Company's overall exposure to credit risk since these customers might be affected by similar economic or other conditions, management believes the Company is exposed to minimal credit risk, since the majority of its business is conducted with major companies within the industry and much of the business is conducted with companies with whom the Company has joint operations. The Company generally does not require collateral for its accounts receivables. 13. SUBSEQUENT EVENTS Grantor Trust Effective January 12, 1999, the Operating Partnership established a revocable grantor trust (the "Trust") with an initial deposit of $1 million. The purpose of the Trust is to purchase Common Units of the Company to fund future liabilities of a Long-Term Incentive Plan (the "Plan"). Provisions of the Plan were not finalized as of February 15, 1999. The Company intends to consolidate the Trust into its financial statements and disclose the Common Units held by the Trust in a manner similar to a purchase of treasury stock under the cost method of accounting. At February 15, 1999, the Trust had purchased a total of 267,200 Common Units at a cost of $4.8 million. F-20
Sorrento Pipeline Lease Agreement Effective January 1, 1999, Sorrento Pipeline Company, LLC ("Sorrento"), a wholly owned subsidiary of the Operating Partnership, entered into a lease agreement (the "Agreement") with Entell NGL Services ("Entell"). Entell is a joint venture between Sorrento and Tejas NGL Pipelines, LLC. Under terms of the Agreement, Sorrento will lease the Sorrento System (as defined in the Agreement) to Entell for a period of ten years for approximately $1.6 million per year. 14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Amounts in thousands except per Unit data) <TABLE> <CAPTION> First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 1997: <S> <C> <C> <C> <C> Revenues $255,652 $245,380 $268,974 $250,275 Operating income 19,880 12,966 9,728 17,579 Income before minority interest 18,585 12,364 7,475 14,266 Minority interest (186) (123) (75) (143) Net income 18,399 12,241 7,400 14,123 Net Income per Unit $ .33 $ .22 $ .13 $ .25 For the Year Ended December 31, 1998: Revenues $190,517 $207,566 $164,620 $176,199 Operating income 3,316 14,925 7,672 8,613 Income (loss) before extraordinary item and minority interest (319) 15,399 9,802 12,473 Extraordinary item and minority interest 3 (154) (27,002) (125) Net income (loss) (316) 15,245 (17,200) 12,348 Per Unit Data: Earnings (loss) before extraordinary item $ (.01) $ .28 $ .15 $ .18 Extraordinary item (.42) Net income (loss) $ (.01) $ .27 $ (.27) $ .18 </TABLE> F-21
Independent Auditors' Report Belvieu Environmental Fuels: We have audited the accompanying balance sheets of Belvieu Environmental Fuels ("BEF") as of December 31, 1997 and 1998, and the related statements of operations, cash flows and partners' equity for each of the years in the three- year period ended December 31, 1998. These financial statements are the responsibility of BEF's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Belvieu Environmental Fuels at December 31, 1997 and 1998, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1998 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Houston, Texas February 15, 1999 F-22
BELVIEU ENVIRONMENTAL FUELS BALANCE SHEETS (Amounts in Thousands) <TABLE> <CAPTION> December 31, ------------------------------------------ 1997 1998 ------------------------------------------ <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents, including restricted cash of $13,071 and $11,144 in 1997 and 1998, respectively $ 22,522 $ 18,603 Accounts receivable - trade 283 268 Due from affiliates 11,239 9,225 Inventories 2,444 2,242 Prepaid expenses 3,701 3,930 ------------------------------------------ Total current assets 40,189 34,268 PROPERTY, PLANT AND EQUIPMENT, Net 182,945 172,281 DEFERRED START-UP COSTS, Net 8,061 4,479 PROCESS LICENSING FEES, Net 10,019 9,166 OTHER ASSETS 243 39 ------------------------------------------ TOTAL $241,457 $220,233 ========================================== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 39,111 $ 39,111 Accounts payable - trade 4,237 1,930 Accrued expenses 1,919 2,914 Accrued turnaround costs 6,973 5,812 Due to affiliates 5,104 4,559 ------------------------------------------ Total current liabilities 57,344 54,326 LONG-TERM DEBT 58,667 19,556 OTHER LIABILITIES 2,950 1,798 COMMITMENTS AND CONTINGENCIES ------------------------------------------ PARTNERS' EQUITY 122,496 144,553 ------------------------------------------ TOTAL $241,457 $220,233 ========================================== </TABLE> See Notes to Financial Statements F-23
BELVIEU ENVIRONMENTAL FUELS STATEMENTS OF OPERATIONS (Amounts in Thousands) <TABLE> <CAPTION> Year Ended December 31, ----------------------------------------------------------------- 1996 1997 1998 ----------------------------------------------------------------- <S> <C> <C> <C> REVENUES $217,438 $233,218 $182,001 ----------------------------------------------------------------- COST AND EXPENSES Cost of goods sold 173,677 193,254 143,109 Amortization of deferred start-up costs 3,624 3,583 3,583 General and administrative expenses 869 1,282 1,379 ----------------------------------------------------------------- Total 178,170 198,119 148,071 ----------------------------------------------------------------- OPERATING INCOME 39,268 35,099 33,930 ----------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest expense (10,709) (8,004) (5,409) Interest Income 672 832 892 Other, net 25 (9) (12) ----------------------------------------------------------------- Total other income (expense) (10,012) (7,181) (4,529) ----------------------------------------------------------------- NET INCOME $ 29,256 $ 27,918 $ 29,401 ================================================================= </TABLE> See Notes to Financial Statements F-24
BELVIEU ENVIRONMENTAL FUELS STATEMENTS OF CASH FLOWS (Amounts in Thousands) <TABLE> <CAPTION> Year Ended December 31, ----------------------------------------------- 1996 1997 1998 ----------------------------------------------- <S> <C> <C> <C> OPERATING ACTIVITIES Net income $ 29,256 $ 27,918 $ 29,401 Adjustments to reconcile net income to cash flows provided by operating activities: Depreciation and amortization 15,373 15,518 15,536 Effects of changes in operating accounts: Accounts receivable - trade 1,093 94 15 Due from affiliates (9,236) 6,271 2,014 Inventories (4) (283) 202 Prepaid expenses (44) (55) (229) Other assets 260 260 204 Accounts payable - trade 3,763 (5,486) (2,307) Accrued expenses (3,080) 459 995 Accrued turnaround costs (256) 6,720 (1,161) Due to affiliates (8,609) 350 (545) Other liabilities 7 2,279 (1,152) ----------------------------------------------- Operating activities cash flows 28,523 54,045 42,973 ----------------------------------------------- INVESTING ACTIVITIES Capital expenditures, net (239) (128) (437) Deferred start-up costs incurred (275) ----------------------------------------------- Investing activities cash flows (514) (128) (437) ----------------------------------------------- FINANCING ACTIVITIES Long-term debt repayments (39,111) (39,111) (39,111) Contributions from partners 3,000 Distributions to partners (7,344) ----------------------------------------------- Financing activities cash flows (36,111) (39,111) (46,455) ----------------------------------------------- CHANGE IN RESTRICTED CASH FOR: Plant turnaround maintenance 1,142 (9,759) 2,187 Debt service 1,487 (20) (260) ----------------------------------------------- Change in restricted cash 2,629 (9,779) 1,927 ----------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS (5,473) 5,027 (1,992) CASH AND CASH EQUIVALENTS, JANUARY 1 9,897 4,424 9,451 ----------------------------------------------- CASH AND CASH EQUIVALENTS, DECEMBER 31 (Excluding restricted cash of $3,292 in 1996, $13,071 in 1997 and $11,144 in 1998) $ 4,424 $ 9,451 $ 7,459 =============================================== SUPPLEMENTAL CASH FLOW DISCLOSURE Cash payments for interest $ 12,029 $ 7,844 $ 4,945 =============================================== </TABLE> See Notes to Financial Statements F-25
BELVIEU ENVIRONMENTAL FUELS STATEMENTS OF PARTNERS' EQUITY (Amounts in Thousands) <TABLE> <S> <C> Partners' Equity, January 1, 1996 $ 62,322 Net Income 29,256 Contributions from partners 3,000 ----------------- Partners' Equity, December 31, 1996 94,578 Net Income 27,918 ----------------- Partners' Equity, December 31, 1997 122,496 Net Income 29,401 Distributions to partners (7,344) ----------------- Partners' Equity, December 31, 1998 $144,553 ================= </TABLE> See Notes to Financial Statements F-26
BELVIEU ENVIRONMENTAL FUELS NOTES TO FINANCIAL STATEMENTS 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BELVIEU ENVIRONMENTAL FUELS ("BEF") is a Texas general partnership that owns and operates an isobutane dehydrogenation and Methyl Tertiary Butyl Ether ("MTBE") production facility (the "Facility") in Texas. At December 31, 1998, Mitchell Gas Services, L.P. ("Mitchell"), SUN BEF, Inc. ("SUN BEF") and Enterprise Products Operating L.P. (the "Operating Partnership") each owned a one-third interest in BEF. Mitchell Energy & Development Corp. is Mitchell's ultimate parent company; Sun Company, Inc. ("Sun") is SUN BEF's ultimate parent company; and Enterprise Products Company ("EPCO") is the Operating Partnership's ultimate parent. The above companies, who own a portion of BEF, are hereafter collectively referred to as the "Partners." INVENTORIES, consisting of MTBE and methanol feedstocks used in the production of MTBE, are carried at the lower of cost or market. Cost for MTBE inventories is computed using the average cost method, while cost for methanol feedstocks is computed using the last in first out ("LIFO") method. The LIFO reserve on methanol feedstocks was $6,207 and $537,546 at December 31, 1997 and 1998, respectively. EXCHANGES are movements of methanol between parties to satisfy timing and logistical needs of the parties. Methanol borrowed from BEF under product exchange agreements is included in receivables at the year-end average posted price, and methanol loaned to BEF under product exchange agreements is accrued as a liability at the year-end average posted price. PROPERTY, PLANT AND EQUIPMENT is stated at cost. Depreciation is computed using the straight-line method over 20 years. Costs of major maintenance shutdowns at the Facility (turnaround costs) are accrued over the estimated period between turnarounds. DEFERRED START-UP COSTS are the costs to modify and replace certain equipment and the net costs and expenses in excess of revenues from the sales of products that BEF incurred during the Facility's start-up phase. Such costs are being amortized over a five-year period. Accumulated amortization for the deferred start-up costs was $6.3 million, $9.9 million and $13.4 million at December 31, 1996, 1997 and 1998, respectively. See Note 2 for recently issued accounting standards. PROCESS LICENSING FEES are fees paid to the designer of the process that the Facility uses to produce MTBE. Such fees are being amortized on a straight-line basis over a period of 15 years. Accumulated amortization for the process licensing fees was $1.4 million, $2.2 million and $3.1 million at December 31, 1996, 1997 and 1998, respectively. INCOME TAXES are not provided because BEF's taxable income is reported directly by the Partners. CASH FLOWS are computed using the indirect method. For cash flow purposes, BEF considers all highly liquid debt instruments with an original maturity of less than three months at the date of purchase to be cash equivalents. USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period are required for the preparation of financial statements in conformity with generally accepted accounting principles. Actual results could differ from these estimates. F-27
INTEREST RATE CAP AGREEMENTS are used as a hedge against potential interest rate increases in BEF's long-term debt; accordingly, when interest rates exceed the cap rate, a reduction to interest expense is recorded based on the rate differential and the outstanding notional amount. The costs of the agreements are being amortized over the lives of the agreements. DOLLAR AMOUNTS presented in the tabulations within the notes to BEF's financial statements are stated in thousands of dollars, unless otherwise indicated. CASH DISTRIBUTIONS to the partners are made in accordance with their partnership interests. Certain reclassifications have been made to the prior years' financial statements to conform to the presentation of the current period financial statements. 2. RECENTLY ISSUED ACCOUNTING STANDARDS On April 3, 1998, the American Institute of Certified Public Accountants issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up Activities." For years beginning after December 15, 1998, SOP 98-5 requires that all start-up costs of a business activity be charged to expense as incurred and any start-up costs previously deferred should be written off as a cumulative effect of a change in accounting principle. At January 1, 1999, BEF will record a $4.5 million noncash write-off of the unamortized balances of deferred start-up costs. Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" is effective for all fiscal quarters of fiscal years beginning after June 15, 1999. Management is currently studying this SFAS item for possible impact on the financial statements. 3. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment and accumulated depreciation were as follows: <TABLE> <CAPTION> 1997 1998 --------------------------------- <S> <C> <C> Land....................................................... $ 577 $ 577 Property, plant and equipment.............................. 221,720 222,135 Construction in progress................................... 34 56 --------------------------------- Total property............................................. 222,331 222,768 Accumulated depreciation .................................. (39,386) (50,487) --------------------------------- Property, net.............................................. $182,945 $172,281 ================================= </TABLE> 4. LONG-TERM DEBT BEF's long-term debt consists of a five-year term loan with a bank syndicate. The debt is payable in quarterly installments of $9.8 million. Maturities of long-term debt at December 31, 1998 are as follows: $39.1 million in 1999 and $19.6 million in 2000. Interest on such debt is at a base rate plus a specified margin for each base interest rate available under the agreement. BEF periodically elects the base interest rate using various standard bank rates (banks' prime rate, fixed certificate of deposit rate, Eurodollar rate or the London Interbank Offered Rate ["LIBOR"] ). The weighted-average interest rate for the year ended December 31, 1998 was 6.6%. At December 31, 1998, BEF had an interest rate cap agreement (based on a LIBOR of 7%) with a notional amount of $13.4 million. The agreement provides that the notional amount will decrease by $4.5 million each quarter through September 1999. BEF intends to hold the contract through its expiration date and use it as a means of fixing the interest on a portion of the term note payable. While the notional amount is used to express the magnitude of an interest rate cap agreement, the amount potentially subject to credit risk (in the event of nonperformance by a third party) is substantially smaller. BEF does not anticipate any significant impact to its financial position as a F-28
result of nonperformance by a third party. The interest rate cap did not have a significant effect on interest expense recognized by BEF in 1996, 1997 or 1998. Long-term debt is collateralized by substantially all of the assets shown on the accompanying balance sheets. The loan agreement with the banks contains restrictive covenants prohibiting or limiting certain actions of BEF, including partner distributions, and requiring certain actions by BEF, including the maintenance of specified levels of debt-to-equity ratio and approval by the banks of certain contracts. In addition, the loan agreement requires BEF to restrict a certain portion of cash to pay for the plant's turnaround maintenance and long-term debt service. Such amounts are presented on the accompanying balance sheets as restricted cash. BEF was in compliance with the restrictive covenants at December 31, 1998. 5. COMMITMENTS AND CONTINGENCIES BEF has methanol supply contracts with three independent suppliers. Under terms of the contracts, the suppliers have generally agreed to supply BEF with a portion of its monthly methanol requirements. BEF has no obligation to take any minimum volumes of methanol under these contracts. The price paid to the suppliers for methanol purchased is generally determined at the beginning of each month; such price is expected to approximate the posted monthly market price for methanol. 6. FAIR VALUE OF FINANCIAL INSTRUMENTS The following disclosure of estimated fair value was determined by BEF, using available market information and appropriate valuation methodologies. Considerable judgment, however, is necessary to interpret market data and develop the related estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that BEF could realize upon disposition of the financial instruments. The use of different market assumptions and/or estimation methodologies could have a material effect on the estimated fair value amounts. Cash and Cash Equivalents, Accounts Receivable - Trade, Accounts Payable - Trade, Accrued Expenses, and Long-Term Debt are carried at amounts that approximate their fair value. The Interest Rate Cap Agreement is valued at amortized cost. Fair value is based on estimates obtained from a dealer and was $4,800 at December 31, 1997 and zero at December 31, 1998. 7. CONCENTRATION OF CREDIT RISK Substantial portions of BEF's revenues are derived from the production and sales of MTBE to Sun, who also operates in the same industry, primarily located in the United States. Although this concentration could affect BEF's overall exposure to credit risk since this customer might be influenced by similar economic or other conditions, management believes BEF is exposed to minimal credit risk, since Sun is a partner in BEF. 8. RELATED PARTY TRANSACTIONS The Operating Partnership has been designated by the Partners as the Facility's operator. In addition, BEF sells the Operating Partnership by-products which are recorded as an offset to cost of goods sold. The Partners are required under isobutane supply contracts to provide their pro rata share of BEF's monthly isobutane requirements. If the Facility's isobutane requirements exceed 450,000 barrels for any given month, SUN BEF and Mitchell retain the right, but not the obligation, to supply at least one-third of the additional isobutane needed. The purchase price for the isobutane (which generally approximates the established market price) is based on contracts with the Partners. Payables related to the isobutane purchases are included in accounts payable and accrued expenses in the accompanying balance sheets. F-29
BEF has a ten-year off-take agreement with Sun. Under terms of the amended agreement (dated August 16, 1995), Sun is required to purchase all of the Facility's MTBE production. Through May 31, 2000, Sun pays the higher of floor price or market price (as defined within the agreement) for the floor production (193,450,000 gallons per year or 530,000 gallons per day), the market price for production between 530,000 and 588,000 gallons per day and Posted Spot Prices for production in excess of 588,000 gallons per day. At floor production levels, the floor price is a price sufficient to cover essentially all operating costs plus principal and interest payments on the bank term loan. Market price is (a) the toll fee price (cost of feedstock plus approximately $0.484 per gallon during the first two contract years ended May 31, 1997) and (b) at Sun's option, the toll fee price (cost of feedstock plus approximately $0.534 per gallon) or the U.S. Gulf Coast Posted Contract Price for the period from June 1, 1997 through May 31, 2000. For purposes of computing the toll fee price, the feedstock component is based on the Normal Butane Posted Price for the month plus the average purchase price paid by BEF to acquire methanol consumed by the Facility during the month. In addition, the floor or market price determined above will be increased by $0.03 per gallon in the third and fourth contract years and by about $0.04 per gallon in the fifth contract year. Beginning June 1, 2000, through the remainder of the agreement, the price for all production will be based on a market-related negotiated price. The contracted floor price paid by SUN for production in 1996, 1997 and 1998 exceeded the spot market price for MTBE. At December 31, 1998 the floor price paid for MTBE by SUN was $.78 per gallon. The average Gulf Coast MTBE spot price was $.46 per gallon for December 1998 and $.64 per gallon for all of 1998. The following is a summary of transactions with related companies (amounts in thousands): <TABLE> <CAPTION> For the Year Ended December 31, --------------------------------------------------- STATEMENTS OF OPERATIONS: 1996 1997 1998 - ------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> Sales of MTBE $217,438 $233,218 $182,001 Cost of goods sold 113,337 113,962 83,426 General and administrative expenses paid to EPCO 518 539 552 </TABLE> F-30
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas, on the 11th day of March, 1999. ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership) By: Enterprise Products GP, LLC, as General Partner By: /s/ O.S. Andras --------------------------------- Name: O.S. Andras Title: President and Chief Executive Officer of Enterprise Products GP, LLC Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on the 11th day of March, 1999. Signature Title /s/ Dan L. Duncan Chairman of the Board and Director - ------------------------------- Dan L. Duncan /s/ O.S. Andras President, Chief Executive Officer and - ------------------------------- Director O.S. Andras /s/ Randa L. Duncan Group Executive Vice President and - ------------------------------- Director Randa L. Duncan /s/ Gary L. Miller Executive Vice President, Chief Financial - ------------------------------- Officer, Treasurer and Director (Principal Gary L. Miller Financial and Accounting Officer) /s/ Dr. Ralph S. Cunningham Director - ------------------------------- Dr. Ralph S. Cunningham /s/ Lee W. Marshall Director - ------------------------------- Lee W. Marshall, Sr. S-1